                                                                                     ACCEPTED
                                                                                03-14-00735-CV
                                                                                        4703327
                                                                       THIRD COURT OF APPEALS
                                                                                 AUSTIN, TEXAS
                                                                           3/31/2015 9:04:27 AM
                                                                               JEFFREY D. KYLE
                                                                                          CLERK
                           No. 03-14-00735-CV

                              IN THE                             FILED IN
                                                          3rd COURT OF APPEALS
                      THIRD COURT OF APPEALS                  AUSTIN, TEXAS
                         AT AUSTIN, TEXAS                 3/31/2015 9:04:27 AM
                                                            JEFFREY D. KYLE
                        Entergy Texas, Inc., et al.,              Clerk
                                        Appellants

                                    v.

                Public Utility Commission of Texas, et al.,
                                        Appellees

      Appeal from the 353rd Judicial District Court, Travis County, Texas
                The Honorable John K. Dietz, Judge Presiding
 ________________________________________________________________

                      APPELLANT’S BRIEF
                    OF ENTERGY TEXAS, INC.
_________________________________________________________________

                                John F. Williams
                                State Bar No. 21554100
                                jwilliams@dwmrlaw.com
                                Marnie A. McCormick
                                State Bar No. 00794264
                                mmccormick@dwmrlaw.com
                                DUGGINS WREN MANN & ROMERO, LLP
                                600 Congress Ave., Ste. 1900 (78701)
                                P. O. Box 1149
                                Austin, Texas 78767-1149
                                (512) 744-9300
                                (512) 744-9399 fax

                                ATTORNEYS FOR APPELLANT
                                ENTERGY TEXAS, INC.


March 2015

                    ORAL ARGUMENT REQUESTED
                   IDENTITY OF PARTIES AND COUNSEL

      The following is a list of all parties to the order appealed from and the names

and addresses of all trial and appellate counsel:

Parties:                                       Attorneys:

Entergy Texas, Inc.                            John F. Williams
Plaintiff in District Court                    Marnie A. McCormick
                                               Duggins Wren Mann & Romero, LLP
                                               600 Congress Ave., Ste. 1900 (78701)
                                               P. O. Box 1149
                                               Austin, Texas 78767-1149
                                               Counsel in District Court and on Appeal

Public Utility Commission of Texas             Elizabeth R. B. Sterling
Defendant in District Court                    Assistant Attorney General
                                               Environmental Protection Division
                                               Office of the Attorney General
                                               P.O. Box 12548
                                               Austin TX 78711-2548
                                               Counsel in District Court and on Appeal

Office of Public Utility Counsel               Sara J. Ferris
Plaintiff/Intervenor in District Court         Office of Public Utility Counsel
                                               1701 N. Congress Ave., Ste. 9-180
                                               Austin TX 78711-2397
                                               Counsel in District Court and on Appeal

Cities of Bridge City, et al.                  Daniel J. Lawton
Plaintiff/Intervenor in District Court         Lawton Law Firm PC
                                               12600 Hill Country Blvd., Ste. R275
                                               Austin TX 78738
                                               Counsel in District Court




                                           i
State Agencies                                Susan M. Kelley (retired)
Plaintiff/Intervenor in District Court        Office of the Attorney General
                                              P. O. Box 12548
                                              Austin TX 78711-2548
                                              Counsel in District Court

Texas Industrial Energy Consumers             Meghan Griffiths
Intervenor in District Court                  Andrews Kurth LLP
                                              111 Congress Ave., Ste. 1700
                                              Austin TX 78701
                                              Counsel in District Court

                                              Rex VanMiddlesworth
                                              Benjamin Hallmark
                                              Thompson Knight LLP
                                              98 San Jacinto Blvd., Ste. 1900
                                              Austin, Texas 78701
                                              Counsel in District Court




                                         ii
                                       TABLE OF CONTENTS

IDENTITY OF PARTIES AND COUNSEL ............................................................ i 

TABLE OF CONTENTS ......................................................................................... iii 

INDEX OF AUTHORITIES.................................................................................... vi 

STATEMENT OF THE CASE ................................................................................ ix 

STATEMENT REGARDING ORAL ARGUMENT ............................................. ix 

ADMINISTRATIVE RECORD .............................................................................. ix 

ISSUES PRESENTED...............................................................................................x 

STATEMENT OF FACTS ........................................................................................1 

I.      Regulatory Framework ....................................................................................1 

II.     Procedural History ...........................................................................................4 

SUMMARY OF THE ARGUMENT ........................................................................5 

ARGUMENT AND AUTHORITIES ........................................................................7 

I.      The Commission erred in disallowing over $11 million associated
        with ETI’s unrecovered Hurricane Rita reconstruction costs. ........................7 

        A.       Background ...........................................................................................7 

        B.       The Commission erred as a matter of law in concluding that
                 PURA required the insurance proceeds to be trued-up in Docket
                 No. 37744. ...........................................................................................13 

        C.       The Commission also erred in treating the issue as if it had in
                 fact been resolved in Docket No. 37744. ............................................15 

        D.       The Commission’s order contravenes legislative intent. ....................18 

II.     The Commission erred in refusing to include any of ETI’s adjustments
        to test-year purchased capacity costs in setting rates. ...................................19 

        A.       Background .........................................................................................19 

                                                          iii
        B.      The Commission misapplied the standard for adjustments to
                test-year expenses. ...............................................................................24 

                1.       Adjustments to test-year data are not extraordinary relief........24 

                2.       Adjustments to test-year data need not be proven with
                         absolute certainty. .....................................................................26 

        C.      The Commission’s wholesale disallowance of any adjustment
                to test-year levels of capacity costs is not supported by
                substantial evidence.............................................................................27 

                1.       ETI proved that it will incur an annual capacity cost
                         increase of $15.8 million under the Frontier contract...............28 

                2.       ETI proved that it will incur an annual capacity cost
                         increase of $8.1 million under the SRMPA contract. ...............30 

                3.       ETI proved that it will incur an annual capacity cost
                         increase of $14.1 million under the Calpine contract. ..............31 

                4.       The record does not reasonably support the
                         Commission’s other reasons for disallowing 100 percent
                         of these known capacity costs. ..................................................32 

                         a.        Load Growth ...................................................................32 

                         b.        MSS-1 Costs ...................................................................34 

                         c.        MSS-4 Costs ...................................................................36 

        D.      The consequences of the Commission’s decision are extreme
                and unjust. ...........................................................................................38 

III.    The Commission erred in setting ETI’s transmission equalization
        (MSS-2) expense at the test-year level. .........................................................39 

        A.      The Commission erred as a matter of law in applying the
                standard for adjustments to test-year expenses. ..................................41 

        B.      Additionally, the Commission’s adherence to test-year expense
                levels is unsupported by substantial evidence.....................................42 

CONCLUSION AND PRAYER .............................................................................43 
                                                         iv
CERTIFICATE OF COMPLIANCE .......................................................................44 

CERTIFICATE OF SERVICE ................................................................................45 

APPENDICES .........................................................................................................47 




                                                          v
                                      INDEX OF AUTHORITIES

Cases 
B.L.M. v. J.H.M., III,
  No. 03-14-00050-CV, 2014 WL 3562559 *11 (Tex. App. – Austin Jul. 17,
  2014, pet. denied) .................................................................................................17
Bluefield Waterworks & Improvement Co. v. Public Serv. Comm’n of State
  of W.Va.,
  262 U.S. 679 (1923) ...............................................................................................2
Cameron v. Terrell & Garrett, Inc.,
 618 S.W.2d 535 (Tex. 1981) ................................................................................33
Cities of Dickinson v. Public Util. Comm’n of Tex.,
  284 S.W.3d 449 (Tex. App. – Austin 2009, no pet.) ...........................................11
City of Corpus Christi v. Public Util. Comm’n of Tex.,
  51 S.W.3d 231 (Tex. 2001) ..................................................................................10
City of El Paso v. Public Util. Comm’n of Tex.,
  344 S.W.3d 609 (Tex. App. – Austin 2011, no pet.) ................................ 3, 19, 20
City of El Paso v. Public Util. Comm’n of Tex.,
  883 S.W.2d 179 (Tex. 1994) ............................................................... 3, 25, 26, 41
Commint Technical Services, Inc. v. Quickel,
 314 S.W.3d 646 (Tex. App. – Houston [14th Dist.] 2010, no pet.) ......................16
Entergy Gulf States, Inc. v. Public Util. Comm’n of Tex.,
  173 S.W.3d 199 (Tex. App. – Austin 2005, pet. denied) ......................................1
Federal Power Comm’n v. Hope Natural Gas Co.,
  320 U.S. 591 (1944) ...............................................................................................2
Idaho Power Co. v. Idaho State Tax Comm'n,
  109 P.3d 170 (Idaho 2005) ...................................................................................10
Office of Consumer Counsel v. Department of Public Util. Control,
  742 A.2d 1257 (Conn. 2000) ................................................................................10
Office of Consumer Counsel v. Department of Public Util. Control,
  905 A.2d 1 (Conn. 2006) .....................................................................................10
Office of Public Util. Counsel v. Public Util. Comm’n of Tex.,
  104 S.W.3d 225 (Tex. App. – Austin 2003, no pet.) .............................................2


                                                          vi
Starr County v. Starr Industrial Servs., Inc.,
  584 S.W.2d 352 (Tex. Civ. App. – Austin 1979, writ ref’d n.r.e.) ......................27
State of Texas' Agencies & Institutions of Higher Learning v. Public Util.
  Comm’n of Tex.,
  450 S.W.3d 615 (Tex. App. -- Austin 2014, pet. requested) ........................ 10, 17
Suburban Util. Corp. v. Public Util. Comm’n of Tex.,
  652 S.W.2d 358 (Tex. 1983) ........................................................................... 3, 26
TXU Elec. Co. v. Public Util. Comm’n of Tex.,
  51 S.W. 3d 275 (Tex. 2001) (per curiam) ..............................................................8
Woods v. William M. Mercer, Inc.,
 769 S.W.2d 515 (Tex. 1988) ................................................................................16
Statutes 
Tex. Gov’t Code Ann. § 2001.174 .............................................................. 19, 39, 43
Tex. Gov’t Code Ann. § 2001.190...........................................................................17
Tex. Util. Code Ann. §§ 11.001, et seq. ....................................................................1
Tex. Util. Code Ann. §§ 36.001, et seq. ..................................................................14
Tex. Util. Code Ann. § 36.003 ...................................................................................2
Tex. Util. Code Ann. § 36.051 .................................................................. 2, 7, 25, 41
Tex. Util. Code Ann. §§ 39.001-.359 ........................................................................2
Tex. Util. Code Ann. § 39.452 ...............................................................................2, 8
Tex. Util. Code Ann. § 39.455 .................................................................................33
Tex. Util. Code Ann. § 39.458 ........................................................................ 7, 8, 18
Tex. Util. Code Ann. §§ 39.458-463 .................................................................. 7, 18
Tex. Util. Code Ann. § 39.459 ............................................................................ 7, 13
Tex. Util. Code Ann. § 39.462 ......................................................................... passim
Rules 
16 Tex. Admin. Code § 22.222 ................................................................................17
16 Tex. Admin. Code § 25.181 ..................................................................................4
16 Tex. Admin. Code § 25.231 ..................................................................... 3, 24, 41
16 Tex. Admin. Code § 25.234 ..................................................................................3
16 Tex. Admin. Code §§ 25.235-.237 .......................................................................4
                                                       vii
16 Tex. Admin. Code § 25.236 ......................................................................... 19, 20
16 Tex. Admin. Code § 25.238 ................................................................................20
Tex. R. Civ. P. 94 .....................................................................................................15
Commission	Proceedings 
Application of Entergy Gulf States, Inc. for Authority to Change Rates and
  to Reconcile Fuel Costs, Docket No. 34800 ........................................................13
Application of Entergy Gulf States, Inc. for Determination of Hurricane
  Reconstruction Costs, Docket No. 32907 .................................................... passim
Application of Entergy Texas, Inc. for Authority to Change Rates and
  Reconcile Fuel Costs, Docket No. 37744 ............................................................17




                                                          viii
                             STATEMENT OF THE CASE

       This is a suit for judicial review of the final order of the Public Utility

Commission of Texas (the “Commission” or “PUCT”) in its Docket Number

39896, a proceeding initiated by Entergy Texas, Inc. (“ETI” or the “Company”) for

authority to change its retail electric rates and reconcile fuel costs. ETI and several

other parties to the contested case sought judicial review of the Commission’s

order.1 The cases were consolidated.2 The district court, Judge John K. Dietz

presiding, reversed the Commission’s order in one respect and summarily affirmed

it in all other respects.3

                STATEMENT REGARDING ORAL ARGUMENT

       Cases involving public utility regulation usually involve complex regulatory

principles, and this one is no exception. For that reason, the Court’s decisional

process would be aided by oral argument.

                             ADMINISTRATIVE RECORD

       The Administrative Record (“AR”) comprises Joint Exhibits 4-13 of the

Reporter’s Record. Joint Exhibit 13 was sealed per the requirements of Texas Rule

of Civil Procedure 76a.4 Joint Exhibits 1-3 are indices to the record.



1
  Clerk’s Record (“CR”) 5. The Clerk’s Record does not yet contain the petitions filed by parties
other than ETI.
2
  CR 81.
3
  CR 2118.
4
  CR 2109.
                                               ix
                           ISSUES PRESENTED


1.   The Commission disallowed over $11 million of costs that ETI incurred to
     restore its system after Hurricane Rita and that no one disputes ETI is
     entitled to recover. The Commission decided that ETI should have begun
     recovering these costs at the end of a previous rate case, Docket No. 37744,
     based upon a PURA provision and what the Commission characterizes as an
     ambiguity in the resolution of Docket No. 37744.

     a.    Did the Commission erroneously interpret PURA as requiring
           resolution of this issue in Docket No. 37744, when PURA section
           39.462(a) says ETI may recover these costs in “any” proceeding
           authorized by Chapter 36?

     b.    Did the Commission err by requiring ETI to disprove its opponents’
           res judicata theory that the order in Docket No. 37744 bars ETI from
           seeking recovery of the costs in this case?

     c.    Does the record reasonably support the Commission’s decision that
           the order in Docket No. 37744 required ETI to begin recovering these
           costs, when everyone agrees the Commission’s order said nothing
           about the issue?


2.   The Commission disallowed over $30 million of ETI’s expenses for
     purchasing capacity from third parties because the amount was not incurred
     in the test year and because the Commission found there was a possibility
     that some of the costs might be avoided or offset.

     a.    Did the Commission err as a matter of law by treating adjustments to
           test-year levels of expense as “exceptional” and by refusing to make
           any adjustments for anticipated costs?

     b.    Is every one of the Commission’s multiple theories about how the
           costs might be avoided or offset supported by substantial evidence?




                                       x
3.   The Commission refused to make any adjustment to ETI’s test-year level of
     “transmission equalization” expense because the parties disagreed about
     how big an adjustment was warranted.

     a.    Did the Commission err as a matter of law by requiring proof of
           adjustments to test-year expenses with absolute certainty?

     b.    Is the Commission’s decision to set this expense at the test-year level
           supported by substantial evidence, when every witness who testified
           on this issue agreed the test-year level was too low?




                                       xi
                               STATEMENT OF FACTS

        ETI is an investor-owned electric utility.5 ETI provides bundled generation,

transmission, distribution, and customer services to over 400,000 retail customers,

primarily in southeastern Texas.6 During the time periods at issue in this case, ETI

served both wholesale and retail customers.

I.     Regulatory Framework

       ETI is a subsidiary of Entergy Corporation, which also owns other

subsidiaries, or “operating companies,” including electric utilities in Louisiana,

Arkansas, and Mississippi.7 The utility subsidiaries each own facilities separately,

but they have historically coordinated and shared resources for providing and

transmitting energy.8      This coordination across state lines is governed by the

“Entergy System Agreement,” a tariff approved by the Federal Energy Regulatory

Commission (“FERC”).9 ETI’s wholesale rates are also regulated by the FERC.

See Entergy Gulf States, Inc. v. Public Util. Comm’n of Tex., 173 S.W.3d 199, 207

(Tex. App. – Austin 2005, pet. denied).

       The services ETI provides to Texas retail customers are subject to regulation

by the PUCT under the Public Utility Regulatory Act (“PURA”).10 The Texas


5
  AR Binder 31, ETI Exh. 4 (Domino Direct at 1 of 38).
6
  Id.
7
  Id.
8
  AR Binder 36, ETI Exh. 39 (Cicio Direct at 6-10 of 75).
9
  Id.
10
   See Tex. Util. Code Ann. §§ 11.001, et seq.
                                               1
legislature in 1999 ordered electric utilities to “unbundle” their generation,

transmission, distribution, and customer service functions as part of an effort to

introduce competition into the Texas retail electric industry. See Tex. Util. Code

Ann. §§ 39.001-.359. However, in 2009, the legislature amended PURA to require

ETI to cease activities relating to the transition to retail competition. See id.

§ 39.452(i). Accordingly, ETI remains subject to traditional cost-of-service rate

regulation. Id. § 39.452(a).

      Under traditional regulation, an electric utility provides service, from the

acquisition to delivery of power, to all requesting customers in a service area at a

Commission-approved “just and reasonable” rate.            See Office of Public Util.

Counsel v. Public Util. Comm’n of Tex., 104 S.W.3d 225, 227-28 (Tex. App. –

Austin 2003, no pet.); see also Tex. Util. Code Ann. § 36.003(a). Under PURA

and applicable constitutional principles, a utility is entitled to rates that afford it a

“reasonable opportunity to earn a reasonable return on the utility’s invested capital

used and useful in providing service to the public in excess of the utility’s

reasonable and necessary operating expenses.” Tex. Util. Code Ann. § 36.051;

Federal Power Comm’n v. Hope Natural Gas Co., 320 U.S. 591, 603 (1944);

Bluefield Waterworks & Improvement Co. v. Public Serv. Comm’n of State of

W.Va., 262 U.S. 679, 692 (1923). To set rates, the Commission determines each of

these components, which cumulatively are the utility’s “revenue requirement” or

                                           2
“cost of service.” See, e.g., City of El Paso v. Public Util. Comm’n of Tex., 883

S.W.2d 179, 187 (Tex. 1994); 16 Tex. Admin. Code § 25.231.

         The PUCT by rule has adopted a process by which rates are based on a

historical “test year,” adjusted for known and measurable changes. See 16 Tex.

Admin. Code § 25.231(a). The Commission evaluates the reasonableness of the

utility’s expenses, determines the appropriate level of capital investment (or rate

base) and a reasonable rate of return on that investment, and then allocates the total

revenue requirement among the utility’s various classes of customer.                  Id.

§§ 25.231(b), (c) & .234.

         The central goal of this process is to arrive at cost recovery as representative

as reasonably possible of the utility’s “cost situation expected in the future.”

Suburban Util. Corp. v. Public Util. Comm’n of Tex., 652 S.W.2d 358, 366 (Tex.

1983). The utility generally bears the risk that its actual operating expenses will

exceed the expectations incorporated into the rate, while retail customers bear the

converse risk, during the regulatory “lag” between rate cases. City of El Paso v.

Public Util. Comm’n of Tex., 344 S.W.3d 609, 613 (Tex. App. – Austin 2011, no

pet.).

         Exceptions to this general rule of risk exist for certain categories of costs,

such as fuel costs and energy efficiency costs. For these types of costs, the utility

has a separate rate or “rider” through which it collects its projected costs. The

                                             3
utility later must reconcile those revenues to its actual, reasonable costs so that it

recovers no more or less than its actual, reasonable costs for the particular category

of expense covered by the rider. See, e.g., 16 Tex. Admin. Code §§ 25.235-.237 &

§ 25.181.

II.    Procedural History

       The Company initiated the underlying general rate case because the rates in

effect did not adequately compensate it for its cost of providing service.11 Among

other things, ETI’s third-party purchased power costs were doubling, a study

showed that its current depreciation rates were severely understated, and its actual

return on equity was some three percentage points lower than its then-authorized

return.12 ETI sought a total annual increase of $104.8 million.13 The “test year”

for the Company’s application was July 1, 2010 through June 30, 2011.14 Rates

were proposed to go into effect in June 2012.15

       After an evidentiary hearing, four Administrative Law Judges (“ALJs”)

issued a proposal for decision recommending that ETI’s rates be increased by a

total of $28.3 million annually.16 The Commission, with a few exceptions, adopted




11
   AR Binder 31, ETI Exh. 4 (Domino Direct at 7 of 38).
12
   Id. at 7-8.
13
   AR Binder 37, ETI Exh. 55 (LeBlanc Rebuttal at 7 of 14).
14
   AR Binder 31, ETI Exh. 4 (Domino Direct at 8 of 38).
15
   AR Binder 43, Vol. K (5/2/12 Tr. at 1540).
16
   See AR Binder 7, Item 244 (Order on Rehearing at 1).
                                              4
the proposal for decision and ordered that ETI’s rates be increased by a total of

$27.7 million annually.

       ETI appealed several aspects of the final order to the district court.17 Several

parties that intervened in the Commission proceeding, including a group of cities

(“Cities”), the Office of Public Utility Counsel (“OPUC”), and State Agencies,

also appealed.18 The district court sustained one of ETI’s points, reversing the

Commission’s decision on that issue.19            The court summarily affirmed the

Commission’s order in other respects.20 More detailed facts are explained below in

the context of the specific errors ETI brings to this Court.

                        SUMMARY OF THE ARGUMENT

       This case is about several multi-million-dollar outlays that ETI made to

serve its customers, but that the Commission refused to include in ETI’s rates.

       First, ETI spent millions of dollars reconstructing its system after Hurricane

Rita. The Commission long ago determined these costs were reasonable and

necessary, and that ETI was entitled to recover them.                   Nevertheless, the

Commission has now disallowed over $11 million of these costs on the theory that

ETI should have started recovering them after its 2009 rate case. This decision is

17
    CR 5.
18
    Though the separate appeals were consolidated, CR 81, the Clerk’s Record does not yet
contain the petitions filed by parties other than ETI. In any event, after the cases were
consolidated, State Agencies nonsuited their appeal but remained in the case as an intervenor
defendant. CR 2084 & 2085.
19
    CR 2118.
20
   Id.
                                             5
based upon an erroneous interpretation of a PURA provision. It is also based upon

a legally and factually unsupportable conclusion that ETI should have divined that

it was required to begin recovering these costs after the 2009 rate case, even

though the order in that case said no such thing.

      Second, ETI spent millions of dollars purchasing third-party capacity to

serve its customers. Even though the Commission did not find that these purchases

were unreasonable or unnecessary, the Commission refused to include the costs in

ETI’s rates. The Commission’s decision is based upon an erroneous insistence that

test-year data is more important than evidence of what costs the Company expects

to bear when the rates go into effect. It is also based upon several fact-findings

that ETI might be able to avoid or offset some of these costs. These findings do

not support a total disallowance of the purchased capacity costs and are not

rationally based upon the record evidence.

      Similarly, ETI spent millions of dollars to pay for its share of the multi-

jurisdictional transmission network that supports service to its customers, and those

costs dramatically increased after the test year. Even though every witness who

testified about this issue agreed that the test-year level of this expense was too low,

the Commission refused to make any adjustment because the witnesses did not

agree on how much of an increase was warranted.             This decision is another

example of the Commission’s erroneous application of the standard for calculating

                                          6
expenses that should be included in rates. It is also unsupported by substantial

evidence.

      The effect of all these decisions was that ETI had to bear all these costs at

shareholder expense until its next rate case. ETI, therefore, did not have the

opportunity to earn the reasonable return on its investment to which it is entitled

under PURA. See Tex. Util. Code Ann. § 36.051. Because these decisions were

fraught with error, this Court should reverse them.

                      ARGUMENT AND AUTHORITIES

I.    The Commission erred in disallowing over $11 million associated with
      ETI’s unrecovered Hurricane Rita reconstruction costs.

      A.     Background

      In 2005, Hurricane Rita struck the upper Texas coast, causing extensive

damage to southeastern Texas. The next year, the legislature enacted a set of

provisions in PURA that entitles electric utilities like ETI to timely recover

reconstruction costs they reasonably and necessarily incurred as a result of the

hurricane. See Tex. Util. Code Ann. §§ 39.458-463.

      The enactment requires the Commission, upon application by a utility, to

determine whether particular hurricane reconstruction costs were reasonably and

necessarily incurred and thus eligible for recovery.      Id. §§ 39.459(a)(1) &

39.462(b). This determination need not be made in the context of a base-rate

proceeding under PURA Chapter 36. Id. § 39.462(e).
                                         7
       If, upon a utility’s application, the Commission determines it would benefit

ratepayers for the utility to recover eligible costs through “securitization”

financing,21 as opposed to “conventional financing methods,” the Commission

must adopt a financing order authorizing the utility to issue bonds. Id. § 39.458.

The bonds are repaid or secured by charges to ratepayers in the utility’s service

area. E.g., TXU Elec. Co. v. Public Util. Comm’n of Tex., 51 S.W. 3d 275, 277

(Tex. 2001) (per curiam). Alternatively, a utility is entitled to recover eligible

reconstruction costs in a base rate proceeding “or through any other proceeding

authorized by Subchapter C, Chapter 36” of PURA.                       Tex. Util. Code Ann.

§ 39.462(a).

       In December 2006, ETI’s predecessor22 initiated a proceeding to determine

whether certain of its Hurricane Rita reconstruction costs were eligible for

recovery and securitization.23 The parties to that case reached a settlement and




21
    Securitization is a specialized form of debt financing where repayment of bondholders
achieves a high degree of assurance, resulting in very low bond interest rates.
22
   ETI’s predecessor was Entergy Gulf States, Inc. (“EGSI”). EGSI provided retail electric
service in both Texas and Louisiana. In 2005, the Texas Legislature enacted legislation
providing that EGSI could proceed with and complete jurisdictional separation of its Texas and
Louisiana operations to establish two separate, vertically integrated utilities. See Tex. Util. Code
Ann. § 39.452(e). By January 1, 2008, EGSI had separated into ETI, a Texas-only utility, and
Entergy Gulf States Louisiana, L.L.C., a Louisiana-only utility.
23
   See Application of Entergy Gulf States, Inc. for Determination of Hurricane Reconstruction
Costs, Docket No. 32907 (Jul. 5, 2006 Application). Public filings in Docket No. 32907 and
other Commission dockets may be accessed at the Commission’s interchange:
  http://interchange.puc.texas.gov/WebApp/Interchange/application/dbapps/filings/pgSearch.asp
by entering the docket number in the “Control Number” field.
                                                 8
agreed that $381,236,384 of the expenses at issue were eligible.24 Because ETI

expected to receive insurance proceeds of $65,700,000 in the future, the settlement

provided that ETI would deduct that amount from its eligible costs.25 The parties

agreed that ETI should be allowed to securitize $381,236,384, plus carrying costs,

minus the $65.7 million estimated insurance proceeds, plus other qualified costs.26

It was understood that the Company might not receive exactly $65,700,000 in

insurance proceeds, so the parties further agreed that after ETI received all of its

insurance payments, a true-up would occur to determine the difference between the

$65,700,000 estimate and the amount actually received.27 The parties agreed that

ETI would accrue interest on the anticipated payments until they were actually

paid, either by insurance companies or ratepayers.28

       The Commission approved the parties’ agreement.29 The order provided that

if ETI received more insurance payments than estimated, the excess would be

passed through to ratepayers via a rider.30 But the agreed rider was only for over-

recovery. Neither the settlement nor the order specified a method for recovering

any insurance under-recovery from ratepayers.



24
   See Docket No. 32907 (Nov. 17, 2006, Settlement Agreement at 2 of 10).
25
   Id. at 3 of 10.
26
   Id. at 5 of 10.
27
   Id. at 3 of 10.
28
   Id.
29
   See id. (Dec. 1, 2006, Order at 1).
30
   Id. at FOF 30.
                                              9
       By 2009, ETI had received only $46,013,904 in insurance proceeds,

resulting in a $19,686,096 under-recovery of its actual, eligible hurricane

reconstruction costs.31 ETI carried this unrecovered balance on its books, with

interest, as a regulatory asset32 because the Commission’s order in Docket No.

32907 expressly contemplated that ETI would be authorized to recover these

amounts in the future.33

       In 2009, ETI filed a base rate case, Docket No. 37744. By that time, ETI

had recovered most of the insurance proceeds it expected to recover, and it sought

permission to begin recovering the regulatory asset of $19,686,096, plus interest,

on a five-year amortization schedule.34


31
   AR Binder 5, Item 185 (Proposal for Decision at 16).
32
   A “regulatory asset” is a mechanism by which a utility carries a cost on its books as a balance
sheet asset based on the expectation that a regulator will allow the utility to recover the cost over
a period of years in the future instead of at the time the expenditure is made. E.g. Office of
Consumer Counsel v. Department of Public Util. Control, 905 A.2d 1, 7 (Conn. 2006); Idaho
Power Co. v. Idaho State Tax Comm'n, 109 P.3d 170, 173 (Idaho 2005); Office of Consumer
Counsel v. Department of Public Util. Control, 742 A.2d 1257, 1263 (Conn. 2000); City of
Corpus Christi v. Public Util. Comm’n of Tex., 51 S.W.3d 231, 238 (Tex. 2001); State of Texas'
Agencies & Institutions of Higher Learning v. Public Util. Comm’n of Tex., 450 S.W.3d 615,
646 (Tex. App. -- Austin 2014, pet. requested). Public utility commissions often permit utilities
to recover large capital expenditures on this deferred basis to avoid the “rate shock” that could
result if the costs were passed on to ratepayers all at once. E.g., Office of Consumer Counsel,
905 A.2d at 7; Idaho Power Co., 109 P.3d at 173. A regulatory asset is, therefore, a future debt
of the ratepayers. Office of Consumer Counsel, 905 A.2d at 7. Regulatory assets are recovered
over time from ratepayers on an “amortized” schedule. See Idaho Power Co., 109 P.3d at 173;
Office of Consumer Counsel, 742 A.2d at 1263.
33
   Docket 32907 (Dec. 1, 2006, Order at FOF 28) (authorizing ETI to accrue carrying costs on
estimated insurance proceeds until paid by insurance companies or until the trued-up amount “is
recovered in base rates”); AR Binder 5, Item 185 (Proposal for Decision at 19).
34
   AR Binder 5, Item 185 (Proposal for Decision at 16). Again, as explained above in footnote
32, regulatory assets are traditionally “amortized.” That means they are recovered over a period
of time so they are not charged to ratepayers all at once.
                                                 10
       Docket No. 37744 was concluded by a “black box” settlement that did not

mention the Hurricane Rita regulatory asset.35 Neither the parties’ stipulation nor

the PUCT’s order in Docket No. 37744 directed ETI to begin amortizing the

regulatory asset or otherwise prescribed a method for recovering it.                   Neither

indicated an intent to alter ETI’s rights under PURA section 39.462 and the

Commission’s order in Docket No. 32907.36 ETI, therefore, continued to account

for and accrue interest on the unrecovered regulatory asset.

       After Docket No. 37744, ETI received an additional $5.7 million in

insurance proceeds.37 In its next rate case, the one underlying this appeal, ETI

sought permission to begin recovering the updated balance of the reconstruction

costs eligible for recovery. With interest, that balance totaled $26,229,627.38 The

ALJs recommended ETI recover only $15,175,563.39

       The ALJs determined that even though the order in Docket No. 37744 did

not say so, ETI should have begun amortizing the regulatory asset on August 15,

2010, the effective date of the rates approved in that docket.40 The ALJs expressed

two rationales for their decision. First, they concluded that PURA required any

35
    In a “black box” settlement, the parties agree to a total amount that a utility can recover
through its rates without specifying any of the individual numbers used to calculate the amount.
See, e.g., Cities of Dickinson, et al. v. Public Util. Comm’n of Tex., 284 S.W.3d 449, 450 (Tex.
App. – Austin 2009, no pet.).
36
   Docket No. 32907, supra (Nov. 17, 2006, Settlement Agreement; Dec. 1, 2006, Order).
37
   AR Binder 37, ETI Exh. 46 (Considine Rebuttal at 18).
38
   Id.; AR Binder 5, Item 185 (Proposal for Decision at 16).
39
   AR Binder 5, Item 185 (Proposal for Decision at 23).
40
   Id. at 21-22.
                                              11
true-up of insurance proceeds to occur in the first base rate case after the

reconstruction costs were deemed eligible for recovery.41 The ALJs believed that

Docket No. 37744 was that case.42 Second, though they characterized the issue as

a “close call,”43 the ALJs concluded that the amortization of the unrecovered costs

“should be considered as having been approved in Docket No. 37744.”44 They

believed the proposed amortization was not disputed in Docket No. 37744, and that

ETI therefore had the burden of proving the issue was not resolved in the docket.45

Because they believed ETI did not meet that burden, they treated the issue as if it

had already been resolved.46         The ALJs determined that if ETI had begun

amortizing the regulatory asset upon the conclusion of Docket No. 37744, only

$15,175,563 would be left to deal with in this case.47

       The Commission adopted the ALJs’ recommendation.48 This decision must

be reversed, because all the rationales for it are flawed.




41
   Id. at 15 & 21-22.
42
   Id. at 16 & 22.
43
   Id. at 20.
44
   Id. at 22.
45
   Id.
46
   Id.
47
   Id. at 23.
48
   AR Binder 7, Item 244 (Order on Rehearing at 1 & FOFs 19-22).
                                            12
       B.      The Commission erred as a matter of law in concluding that
               PURA required the insurance proceeds to be trued-up in
               Docket No. 37744.

       The ALJs relied upon PURA section 39.459(c) in concluding that the

insurance proceeds were required to be trued up in the first base rate case after the

reconstruction costs were deemed eligible for recovery.49 Section 39.459(c) reads:

       To the extent a utility subject to this subchapter receives insurance
       proceeds, governmental grants, or any other source of funding that
       compensates it for hurricane reconstruction costs, those amounts shall
       be used to reduce the utility’s hurricane reconstruction costs
       recoverable from customers. If the timing of a utility’s receipt of
       those amounts prevents their inclusion as a reduction to the hurricane
       reconstruction costs that are securitized, the commission shall take
       those amounts into account in:

       (1)     the utility’s next base rate proceeding; or

       (2)     any proceeding in which the commission considers hurricane
               reconstruction costs.

Tex. Util. Code Ann. § 39.459 (c) (emphasis added).                      The Commission, in

adopting the ALJs’ construction of this provision, erred as a matter of law.50

       PURA section 39.459(c) requires the Commission to remedy a double-

recovery if a utility receives insurance or grant money for hurricane reconstruction

costs after those same costs have already been securitized. That is the exact


49
   AR Binder 5, Item 185 (Proposal for Decision at 15 & 21-22).
50
   The Commission also erred as a matter of fact in assuming that Docket No. 37744 was ETI’s
first base rate case after the reconstruction costs were deemed eligible for recovery in Docket No.
32907. There was another base rate case filed and decided between Docket Nos. 32907 and
37744. See Application of Entergy Gulf States, Inc. for Authority to Change Rates and to
Reconcile Fuel Costs, Docket No. 34800.
                                                13
opposite of what happened here.           In Docket No. 32907, ETI agreed not to

securitize amounts it expected to recover from insurance.          Therefore, in the

language of the statute, the timing of ETI’s receipt of those amounts did not

prevent their inclusion as a reduction to the amounts that were securitized. The

Attorney General conceded in the district court that the wording of section

39.459(c) “is not an exact match to the circumstances of this case.”51 Indeed,

section 39.459(c) is by its plain terms inapplicable.

          Section 39.462(a), on the other hand, speaks directly to this situation. It

says:

          An electric utility subject to this subchapter is entitled to recover
          hurricane reconstruction costs consistent with the provisions of this
          subchapter and is entitled to seek recovery of amounts not recovered
          under this subchapter … in its next base rate proceeding or through
          any other proceeding authorized by Subchapter C, Chapter 36.

Id. § 39.462(a) (emphasis added).         There is no question that the proceeding

underlying this appeal was authorized by PURA Subchapter C, Chapter 36. See id.

§ 36.001, et seq. Therefore, the Commission was expressly authorized to address

the issue in this case. It certainly was not statutorily required to address the issue

in Docket No. 37744 or some other particular case.




51
     CR 698 (PUCT Initial Brief at 14).
                                           14
       C.      The Commission also erred in treating the issue as if it had
               in fact been resolved in Docket No. 37744.

       Nothing in the settlement agreement or final order in Docket No. 37744 even

mentioned the regulatory asset, much less a method of recovering it. The ALJs

acknowledged that.52 They also recognized that utilities are typically not allowed

to recover regulatory assets without express approval of the Commission.53 The

ALJs nevertheless concluded that the proposed amortization of the regulatory asset

should be “considered to have been approved” in Docket No. 37744.               They

believed that the proposed amortization was not disputed in Docket No. 37744 and

that ETI consequently should be required to prove the issue was not resolved in

Docket No. 37744.54 Both of these assumptions are incorrect.

       First, as a matter of law, ETI did not bear the burden of proving what issues

Docket No. 37744 did or did not resolve. The issue of whether Docket No. 37744

bars ETI from seeking particular relief in a subsequent case was a defensive issue

raised by intervenors.55 The argument is really that the order in Docket No. 37744

is res judicata of the reconstruction cost recovery issue.         Because that is an

affirmative defense, intervenors bore the burden of proof on the issue. See, e.g.,

Tex. R. Civ. P. 94; Woods v. William M. Mercer, Inc., 769 S.W.2d 515, 517 (Tex.


52
   AR Binder 5, Item 185 (Proposal for Decision at 20-21).
53
   Id. at 21.
54
   Id. at 22.
55
   See, e.g., AR Binder 8 (Cities Exh. 2, Garrett Direct at 11).
                                                 15
1988); Commint Technical Services, Inc. v. Quickel, 314 S.W.3d 646, 651 (Tex.

App. – Houston [14th Dist.] 2010, no pet.).

          There is no reasonable basis in the record upon which to conclude that the

parties or the Commission intended ETI to begin amortizing the regulatory asset

years ago. The only reason the intervenors gave in support of their argument was

their allegation that the issue was “undisputed” in Docket No. 37744. It is true that

no party to Docket No. 37744 argued that ETI should not recover the money at

all.56 They could not, given that Docket No. 32907 and PURA clearly entitle ETI

to recover the full amount of its eligible restoration costs. Regardless, the parties’

litigation positions during the contested phase of a proceeding do not inform what

the parties intend when they settle the case, or what the Commission intends in

approving the settlement.

          Even assuming for the sake of argument that the parties’ litigation positions

in Docket No. 37744 were relevant, their positions on whether ETI was entitled to

recover the money at all would not be the relevant issue. What would matter is

what the parties’ positions were on how and when ETI should recover the money,

because that is the issue the Commission says was resolved in Docket No. 37744.

Cities’ witness in Docket No. 37744, Jacob Pous, did dispute ETI’s request to

amortize the regulatory asset over a five-year period. He testified that ETI should


56
     See id. at 11.
                                            16
credit the amount to its storm reserve instead.57 The ALJs were mistaken in

concluding that this issue was uncontested in Docket No. 37744.58 There certainly

is no evidence in this docket that the parties or the Commission intended ETI to

begin amortizing the regulatory asset upon the conclusion of Docket No. 37744.

       Given that neither the settlement agreement nor the Commission’s order said

anything about this issue, and especially since the issue was disputed, ETI would

have been unreasonable to “assume” it could begin amortizing the regulatory asset

when Docket No. 37744 was over. As this Court recently recognized, the recovery

of a regulatory asset is a two-step process. First, the Commission allows creation

of the asset, and later, the Commission decides how the utility may recover the

asset in rates. State of Texas' Agencies & Institutions of Higher Learning v. Public

Util. Comm’n of Tex., 450 S.W.3d 615, 646 (Tex. App. -- Austin 2014, pet

requested). Here, the settlement and Commission order in Docket No. 32907

established that the hurricane reconstruction costs were reasonable and necessary

and authorized creation of the regulatory asset. But the Company’s proposed
57
   See Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel
Costs, Docket No. 37744 (Pous Direct at 113). Both the Commission and this Court may take
notice of the fact this testimony was filed in Docket No. 37744. Tex. Gov’t Code Ann.
§ 2001.190; 16 Tex. Admin. Code § 22.222(a); B.L.M. v. J.H.M., III, No. 03-14-00050-CV, 2014
WL 3562559 *11 (Tex. App. – Austin Jul. 17, 2014, pet. denied) (not designated for
publication).
58
   In contrast, the ALJs correctly observed that another issue – regarding ETI’s storm reserve
balance -- was disputed in Docket No. 37744. AR Binder 5, Item 185 (Proposal for Decision at
48). They concluded that issue was not resolved by the black box settlement. Id. Using the
ALJs’ own logic, this fact leads to the conclusion that the Hurricane Rita issue was not
adjudicated in Docket No. 37744. Resolving two issues differently based on materially similar
facts is the essence of arbitrary and capricious action.
                                             17
method of recovering that asset in Docket No. 37744 was a contested issue, and

neither the parties’ settlement nor the Commission’s order resolved the issue in

favor of one party or another. The only reasonable thing for the Company to do

was to maintain the status quo, carrying the balance on its books as a regulatory

asset until the Commission affirmatively addresses how the Company may recover

it.59

        D.    The Commission’s order contravenes legislative intent.

        The Commission’s decision thwarts the legislature’s purpose in enacting the

hurricane reconstruction cost recovery provisions.             See Tex. Util. Code Ann.

§§ 39.458-.463.      The legislature clearly intended to ensure that utilities that

incurred reconstruction costs as a result of Hurricane Rita would be able to

expeditiously recover those costs in full, with interest. Indeed, the legislature

expressly articulated this purpose in PURA. Id. § 39.458. The effect of the

Commission’s order here is to disallow over $11 million in unrecovered hurricane

reconstruction costs and interest. The order penalizes the utility for, instead of

securitizing all of its hurricane reconstruction costs as authorized by the statute,

opting not to securitize amounts that it anticipated recovering through insurance.

No one has suggested that ETI was unreasonable in estimating its anticipated


59
  Even Cities opined that the Docket No. 37744 settlement should not be interpreted as changing
the status quo unless expressly stated in the settlement agreement or the final order. See AR
Binder 5, Item 185 (Proposal for Decision at 17).
                                              18
insurance proceeds when the securitization docket was taking place.              The

Commission’s reasons for disallowing the amounts that were not ultimately

recovered through insurance are not legally or factually sound. The Court should

reverse the Commission’s disallowance.             See Tex. Gov’t Code Ann.

§ 2001.174(b)(2).

II.    The Commission erred in refusing to include any of ETI’s adjustments
       to test-year purchased capacity costs in setting rates.

       A.    Background

       “Capacity” is the amount of power a utility has available at any given time

to serve customers. Utilities are required to have a percentage surplus or “cushion”

of capacity available in reserve, in case demand exceeds expectations.

Traditionally regulated utilities supply their need for capacity either by owning

generating plants or by buying capacity from someone else.

       A utility’s capital investment in building and maintaining its own plant

become a part of its invested capital (or “rate base”), and the utility earns a return

on that investment. The cost of fueling a power plant and other specified variable

“energy” charges incurred to generate power are recoverable dollar-for-dollar as

fuel expenses. 16 Tex. Admin. Code § 25.236(a); City of El Paso, 344 S.W.3d at

614.

       Purchases of capacity from third parties are, however, treated differently.

They are simply expenses, and earn no return for the utility. Moreover, the fixed
                                         19
costs associated with obtaining capacity from third parties may not, absent special

circumstances, be recovered as fuel expenses.                   16 Tex. Admin. Code

§ 25.236(a)(4); City of El Paso, 344 S.W.3d at 614. Instead, they are recovered

through base rates. Id.60 Like other base rate expenses, “purchased capacity costs”

are quantified during a “test year,” are adjusted for known and measurable

changes, and become a component of the utility’s revenue requirement that forms

the basis for prospective rates.       There is no true-up or reconciliation for the

purchased capacity costs recovered through base rates. Combined with the fact

that there is no opportunity to earn a return on this type of expense, the adverse

financial impact of “regulatory lag” is much more significant for this type of

expense than it is for reconcilable fuel costs.

       Before 2009, ETI was under a regulatory directive to position itself for retail

competition, and that directive necessitated that the Company forego long-term

resource procurement. During that time, ETI relied on or “shared” the capacity

from Entergy System resources owned by other Entergy operating companies, and

relied on short- and limited-term resources to reliably serve its retail customers.61

ETI paid for this Entergy System capacity under Schedule MSS-1 of the Entergy

System Agreement.         That FERC-approved tariff requires the various Entergy

60
   In some circumstances, Commission rules allow utilities to recover purchased capacity costs
through a rider. See 16 Tex. Admin. Code § 25.238. ETI does not have such a rider.
61
   See AR Binder 37, ETI Exh. 47 (Cooper Rebuttal at 5-6 of 21); AR Binder 43, Vol. L (5/3/12
Tr. at 1939).
                                             20
operating companies to make and receive payments according to their relative

share of total system capacity.62 Some Entergy operating companies own a greater

share of Entergy System capacity than they need to serve their own load.63 These

entities are considered “long” on capacity.64 Other companies own less than they

need, and are “short” on capacity.65 Under Schedule MSS-1, “short” companies

pay “long” companies a per-MW rate for the cost of owning these capacity

reserves.66    While it was in regulatory limbo, ETI controlled relatively less

resources compared to its load than other Entergy companies. It, therefore, made

“reserve equalization” payments under Schedule MSS-1.67

       In addition to sharing Entergy System capacity under Schedule MSS-1, ETI

also purchased power from specific units owned by other Entergy operating

companies. Those unit-specific purchases were paid for under contracts with those

operating companies under Schedule MSS-4 of the Entergy System Agreement.

Schedule MSS-4 contains a formula that sets the price of power for these purchases

based on the actual cost of producing the power.68

       After the legislature in 2009 delayed the onset of retail competition in ETI’s

service area, ETI found it cost effective to begin to substantially increase its

62
   AR Binder 36, ETI Exh. 39 (Cicio Direct at 11-12 of 75).
63
   Id. at 12.
64
   Id.
65
   Id.
66
   Id. at 13-14.
67
   AR Binder 35, ETI Exh. 34 (Cooper Direct at 22-23 of 25).
68
   AR Binder 36, ETI Exh. 39 (Cicio Direct at 24-26 of 75).
                                              21
reliance upon purchases of capacity from third parties.69 ETI did not buy more

third-party capacity simply to serve additional load. Rather, ETI employed the

strategy to serve existing load, reduce its reliance on Entergy capacity resources,

and render ETI less “short” compared to other Entergy entities.70 The strategy also

reduced fuel costs for customers because the third-party resources were by and

large more fuel-efficient than the combined Entergy resources and, as explained

above, there was no return component included in the cost.71

       In this case, ETI asked the Commission to recognize the cost of ETI’s

increased reliance on three new third-party purchased capacity contracts. Those

contracts cost ETI some $38 million annually. ETI recognized that these contracts

would enable ETI annually to avoid about $8 million of the costs it paid to Entergy

affiliates for their capacity in the test year. ETI, therefore, asked the Commission

to increase its test-year expenses for purchased capacity by the net amount of about

$30 million for purposes of setting its annual rates.

       No party challenged the wisdom of ETI’s entering into any of the new, third-

party contracts or the prices reflected in the contracts.             The ALJs, however,

included in ETI’s base rates only purchased capacity costs that were incurred



69
   E.g, AR Binder 35, ETI Exh. 34 (Cooper Direct at 23 of 25).
70
   AR Binder 37, ETI Exh. 47 (Cooper Rebuttal at 5 of 21); see also id. at 10-11; AR Binder 37,
ETI Exh. 57 (May Rebuttal at 13-15 of 31).
71
   AR Binder 35, ETI Exh. 34 (Cooper Direct at 24 of 25); AR Binder 37, ETI Exh. 47 (Cooper
Rebuttal at 7-8 of 21).
                                              22
during ETI’s test year.72       The ALJs disallowed 100 percent of the additional

expense associated with the third-party capacity contracts that would be incurred

during the first year rates would be in effect (the “rate year”) and thereafter.73 The

Commission adopted the ALJs’ proposal for decision on this issue.74

       The ALJs concluded that ETI had not proven that the costs it would incur as

a result of entering into the third-party purchase capacity contracts were “known

and measurable” adjustments to the utility’s test-year expenses.75 The ALJs found

that there is “substantial uncertainty” about what ETI will be obligated to pay for

the third-party purchased capacity because the third parties might not fully perform

their obligations under the contracts.76 The ALJs suggested that the contract costs

should not be in rates because they may be offset by increased revenues from load

growth.77 The ALJs further found there is “substantial uncertainty” about how

much money the third-party purchased power capacity contracts will enable ETI to

avoid paying to other Entergy entities under Schedule MSS-1 of the Entergy

System Agreement.78 The source of this perceived uncertainty was apparently the

ALJs’ view that the net costs were difficult to quantify because the calculations



72
   AR Binder 5, Item 185 (Proposal for Decision at FOF 86).
73
   Id. at FOF 73 & 86.
74
   AR Binder 7, Item 244 (Order on Rehearing at 1 & 7).
75
   AR Binder 5, Item 185 (Proposal for Decision at 108).
76
   Id. at FOFs 77-78.
77
   Id. at 109 & FOFs 84.
78
   Id. at FOFs 75, 76, & 79-82.
                                              23
involve projections and “complex” formulae and “variables.”79          Rather than

accepting any of the calculations in evidence or adopting a result within the range

of these recommendations, the ALJs simply disallowed the entire adjustment.80

The Commission’s order adopting these recommendations constitutes error of law

and is not supported by substantial evidence.

       B.     The Commission misapplied the standard for adjustments
              to test-year expenses.

       The fundamental error in the Commission’s order is that it misapplies the

legal standard for determining what expenses should be included in rates. The

order adopts the ALJs’ erroneous view that an adjustment to test-year data is

somehow extraordinary or “exceptional” rate relief.81 The ALJs also took the view

that to the extent additional costs are based on anticipated changes, they cannot be

“known and measurable.”82 These assumptions are wrong as a matter of law.

              1.      Adjustments to test-year data are not extraordinary
                      relief.

       To determine what a utility’s reasonable and necessary expenses are, the

Commission determines “the electric utility’s historical test year expenses as

adjusted for known and measurable changes.” 16 Tex. Admin. Code § 25.231(b).

Under the rule, known and measurable changes have equal weight with historical

79
   Id. at 108.
80
   Id. at 109.
81
   Id. at 108; AR Binder 7, Item 244 (Order on Rehearing at 1).
82
   AR Binder 5, Item 185 (Proposal for Decision at 102).
                                               24
test-year levels.    That makes sense, because PURA does not limit a utility’s

recoverable expenses to those incurred in a historical test year. Rather, PURA

guarantees a utility a reasonable opportunity to earn a reasonable return on its

investment over and above its “reasonable and necessary expenses.” Tex. Util.

Code Ann. § 36.051. The goal of ratemaking is to set utility rates that will meet

the utility’s and customers’ needs in the future, not the past, as rates are set on a

prospective basis.

      The Texas Supreme Court has confirmed that making known and

measurable adjustments is a critical component of establishing the costs upon

which rates are set, and not a rare exception to the use of test-year cost levels. The

Court has explained that “changes occurring after the test period, if known, may be

taken into consideration by the regulatory agency to help mitigate the effects of

inflation and in order to make the test year data as representative as possible of

the cost situation that is apt to prevail in the future.” City of El Paso v. Public

Util. Comm’n of Tex., 883 S.W.2d 179, 188 (Tex. 1994) (emphasis added).

      The recognition of changes to test-year data is especially critical in a case

such as this one, where the inability to recover substantial post-test-year expenses

inevitably causes ETI to recover an inadequate return, contrary to the requirements

of PURA’s fundamental cost-recovery standards.          See Tex. Util. Code Ann.

§ 36.051. The Commission’s conclusion that a utility is somehow less entitled to

                                         25
expenses that occur beyond the test year is contrary to PURA and judicial

precedent, and its erroneous application of the known and measurable standard

tainted the entirety of its decision on this issue. This is reason enough to reverse

the Commission’s decision.

              2.     Adjustments to test-year data need not be proven
                     with absolute certainty.

       The quantum of proof required to establish adjustments to test-year data is

not greater than the quantum required to establish the test-year data itself. The

Texas Supreme Court has held that known and measurable adjustments should be

made if they reflect costs that will be “actually realized,” can be “anticipated with

reasonable certainty,” and if they are representative of the costs “apt” to prevail in

the future. See City of El Paso, 883 S.W.2d at 188; Suburban Util. Corp., 652

S.W.2d at 362. The standard is not an impossible-to-meet requirement of absolute

or virtual certainty. Suburban Util. Corp., 652 S.W.2d at 362. Contrary to its

ruling regarding purchased capacity, the Commission in this and other cases has

routinely adopted known and measurable adjustments that involve estimates and

uncertainty.83     In rejecting ETI’s proposed adjustments to test-year purchased

capacity expense, the Commission did not acknowledge or discuss the statute, rule,

judicial precedent, or regulatory precedent that guide its inquiry. The decision is


83
  E.g., AR Binder 5, Item 185 (Proposal for Decision at 68 (short-term asset update), 163-64
(payroll adjustments), & 182-86 (ad valorem tax rate update)).
                                            26
contrary to and inconsistent with all those authorities. Under the Commission’s

analysis, known and measurable changes routinely adopted by the Commission

would never be allowed. The Commission’s ruling is, therefore, arbitrary and

capricious. See Starr County v. Starr Industrial Servs., Inc., 584 S.W.2d 352, 355-

56 (Tex. Civ. App. – Austin 1979, writ ref’d n.r.e.). This is another reason the

decision must be reversed.

      C.     The Commission’s wholesale disallowance of any
             adjustment to test-year levels of capacity costs is not
             supported by substantial evidence.

      The proposed adjustments for third-party purchased capacity expenses are

attributable to three contracts the parties call the Frontier, Calpine, and Sam

Rayburn Municipal Power Agency (“SRMPA”) contracts. ETI established with

reasonable certainty what costs it would incur under each of these contracts while

the rates being set in this case would be in effect. The Commission did not discuss

the contracts separately, but ruled on them in the aggregate. The Commission said:

      77.    ETI’s projection of its rate-year third-party capacity contract
             payments includes numerous assumptions, one of which is that
             every single third-party supplier will perform at the maximum
             level under the contract, even though that assumption is
             inconsistent with ETI’s historical experience.

      78.    There is substantial uncertainty with regard to ETI’s projection
             of its rate-year third-party capacity contract payments.84


84
  AR Binder 7, Item 244 (Order on Rehearing at FOFs 77-78); see also AR Binder 5, Item 185
(Proposal for Decision at 108-109).
                                           27
         These findings are not supported by substantial evidence. As discussed

below, the adjustments were based on contracts already in place before and during

the rate year. The contracts had clearly and specifically ascertainable prices and

quantities, which were in evidence. No one disputed that ETI will pay money

under these contracts. Rather, some parties speculated that ETI might not have to

pay the full amount of these contracts because suppliers might not perform

perfectly. Performance under each of the contracts is reasonably assured. There is

no reasonable uncertainty regarding the outcome under any of these contracts,

certainly none sufficient to support a finding that none of these contract costs are

“apt to prevail” in the near future.

                 1.     ETI proved that it will incur an annual capacity cost
                        increase of $15.8 million under the Frontier contract.

         There is no reasonable basis in the evidence for the Commission’s finding

that the costs of the Frontier contract are uncertain. ETI has had a contract with

Frontier for years, leading up to and including the first ten months of the test

year.85 In the second-to-last month of the test year, ETI increased the annual

amount of power it purchased under the Frontier contract from 150 MW to 300

MW.86 Applying the language of the Texas Supreme Court, the 150 MW increase

in capacity and capacity cost was “actually realized” in the test year. But because


85
     AR Binder 43, Vol. L (5/3/12 Tr. at 1938 & 1941).
86
     Id. at 1942 & 1959.
                                                28
the step-up happened late in the test year, the test year does not reflect the full

amount of expense ETI will incur going forward under the Frontier contract.87 No

witness challenged ETI’s quantification of what this contract would cost ETI

during the rate year.

       On cross-examination at the hearing, ETI’s witness Cooper acknowledged

that ETI’s purchased capacity contracts include provisions that authorize ETI to

reduce its payments if the counter-party does not perform.88 He explained that ETI

did not assume any reduction in future payments for poor performance because in

the past, any such adjustments have been “relatively minor.”89 ETI’s witness May,

who quantified the increase in annual Frontier costs at $15.8 million, confirmed

that ETI has “quite a bit of experiences” with the contract, and a “good

understanding of what the costs are today and what the costs will be in the future”

under the contract.90 The other parties did not produce evidence to the contrary.

       It is simply not reasonable to conclude, based upon this record, that there is

“substantial uncertainty” about what ETI’s annual expenses will be in connection

with the Frontier increase. The Commission’s findings insofar as they implicate

this contract are not supported by substantial evidence.




87
   Id. at 1942.
88
   AR Binder 43, Vol. F (4/26/12 Tr. at 705-06); see also id. at 682.
89
   Id. at 705.
90
   AR Binder 43, Vol. L (5/3/12 Tr. at 1942).
                                                29
               2.    ETI proved that it will incur an annual capacity cost
                     increase of $8.1 million under the SRMPA contract.

       During the test year, ETI executed a 25-year agreement with SRMPA for

225 MW of capacity.91 Power started flowing under the contract on December 1,

2011, just five months after the end of the test year, well before intervenors filed

their testimony in March 2012, and well before the conclusion of the proceeding

under review.92 All of the capacity contracted for was allocated to ETI.93 The

price of this contract is a “very straightforward $3 per kW a month.”94 It is “very

easy to calculate what those known and measurable costs are.”95 $3.00 x 225,000

kW = $675,000 per month. At $675,000 per month, the contract will cost $8.1

million annually. No witness challenged ETI’s quantification of the annual costs

of the SRMPA contract.          In addition, the SRMPA contract commits “System

Capacity,” meaning multiple network resources and substitute resources are

designated to supply the capacity.           There is no evidence in the record that

SRMPA’s entire portfolio of network resources is likely to be simultaneously

unavailable.

       There is, therefore, no evidence in the record that there is “substantial

uncertainty” about whether SRMPA will perform the contract, or what the annual

91
   AR Binder 35, ETI Exh. 34 (Cooper Direct at 17 of 25).
92
   See id.
93
   Id. at 17 & 19 of 25.
94
   AR Binder 43, Vol. L (5/3/12 Tr. at 1944).
95
   Id.
                                              30
costs of the contract will be. The Commission’s findings insofar as they implicate

this contract are not supported by substantial evidence.

              3.     ETI proved that it will incur an annual capacity cost
                     increase of $14.1 million under the Calpine contract.

       ETI purchased capacity from Calpine Energy Services under a one-year

contract in effect from June 1, 2008 through May 31, 2009.96 In 2009, ETI entered

into a ten-year purchased power agreement with Calpine to purchase 485 MW of

capacity from its Carville Energy Center.97 Purchases under this contract were set

to begin on June 1, 2012, the beginning of the rate year for this case.98 Fifty

percent of the contract was allocated to ETI.99

       The resource had been under contract with the Entergy system for some

time, and the Entergy companies have significant experience with the pricing and

costs under the contract. The most recent contract simply allocated the resource

differently to reflect the fact that the “overhang of retail competition” had been

lifted for ETI.100 Because of ETI’s experience with Calpine, the capacity costs are

“well known.”101 The contract sets out specific capacity quantities and prices, and

includes default and other terms to ensure performance.           ETI’s historical

experience with the Calpine resource establishes that any deviations from the
96
   AR Binder 35, ETI Exh. 34 (Cooper Direct at 21-22 of 25).
97
   Id. at 16.
98
   Id.
99
   Id. at 19 of 25.
100
    See AR Binder 43, Vol. L (5/3/12 Tr. at 1938).
101
    Id. at 1942.
                                              31
negotiated contract payments will be “very, very small.”102 Both parties to the

contract intend and are incentivized to perform such that they will get the full

benefits of the capacity and price under the contract.103 ETI projected the annual

cost of the Calpine contract will be $14.1 million.104

      No witness challenged ETI’s quantification of the costs associated with the

Calpine contract. There is no evidence in the record that there is “substantial

uncertainty” about whether Calpine will perform the contract, or what the annual

costs of the contract will be. The Commission’s findings insofar as they implicate

this contract are not supported by substantial evidence.

             4.     The record does not reasonably support the
                    Commission’s other reasons for disallowing 100
                    percent of these known capacity costs.

                    a.     Load Growth

      Intervenors and Commission staff championed multiple theories they alleged

would offset ETI’s additional expense under these three contracts. One such

theory` was that the cost increase is not known and measurable because it may be

offset by load growth that occurs after the test year.105

      If it were appropriate to consider future load growth in setting base rates,

PURA or the Commission’s rules would say so. Indeed, there are other instances
102
    Id.
103
    Id. at 1942-43.
104
    AR Binder 8 (Cities Exh. 4B [Highly Sensitive], Goins Direct Exh. DWG-2).
105
    AR Binder 5, Item 185 (Proposal for Decision at 109); AR Binder 7, Item 244 (Order on
Rehearing at FOF 84).
                                           32
in which PURA does specify that the utility’s recovery of costs should be subject

to an offsetting load growth adjustment. See, e.g., Tex. Util. Code Ann. § 39.455

(utility entitled to recover specified incremental capacity costs “adjusted for load

growth”). For base rates, the legislature has left load growth out of the equation,

so that it may serve as a source of revenue to address other future cost increases

and avoid or defer additional rate increases. The legislature’s inclusion of “load

growth” language for specific circumstances but not base rates is evidence the

legislature did not intend it to apply generally. Cameron v. Terrell & Garrett, Inc.,

618 S.W.2d 535, 540 (Tex. 1981).

          Even if load growth could properly be considered, however, it does not

support a wholesale disallowance of the increased purchased capacity costs. First,

the load growth that intervenors suggested would occur would not fully materialize

for at least two years.106 It could not logically offset the third-party capacity cost

increases ETI began to experience during or shortly after the test year.

          Second, Cities witness Goins is the only intervenor witness who attempted

to quantify a load growth adjustment, and he quantified it at $15.8 million – a far

cry from the $38 million in increased purchased capacity expense that ETI proved

it would incur.107 Moreover, Mr. Goins’s proposal overstated retail load growth



106
      AR Binder 43, Vol. J (5/1/12 Tr. at 1299-1300 [Confidential]).
107
      AR Binder 8 (Cities Exhs. 4 & 4B [Highly Sensitive], Goins Direct at 9 & 16-19).
                                                 33
significantly and attempted to predict events beyond the rate year.108 It does not

provide a reasonable basis for a known and measurable change at all, much less

one that negates all $38 million of ETI’s third-party capacity contract costs.109

       The large gap between Mr. Goins’s speculative adjustment and the known

costs ETI sought illustrates how far the Commission has strayed from setting rates

at a level that will enable ETI to recover the costs it reasonably expects to incur

when the rates are in effect. In any event, the Commission’s reliance on the load

growth theory to deny ETI any adjustment for its post-test-year increases in third-

party purchased capacity costs is not supported by substantial evidence.

                     b.      MSS-1 Costs

       Another “offset” theory that the Commission adopted concerned the amount

of money ETI might save under Schedule MSS-1 as a result of the new third-party

purchased capacity contracts. The Commission found that the impact the contracts

would have on ETI’s “reserve equalization” payments under Schedule MSS-1 was

substantially uncertain, because the calculation of MSS-1 costs depends on

“numerous assumptions.”110 The record does not support a wholesale disallowance

of ETI’s third-party capacity cost increases on this ground.



108
    Id. at 17-19.
109
    AR Binder 37, ETI Exh. 57 (May Rebuttal at 9-11 of 31); AR Binder 43, Vol. I (5/1/12 Tr. at
pp. 1296-1306, 1316-1324 [Confidential]).
110
    AR Binder 5, Item 185 (Proposal for Decision at 108); AR Binder 7, Item 244 (Order on
Rehearing at 1 & FOFs 75-76).
                                              34
       Company witness Cooper testified that the MSS-1 cost adjustment is a

straightforward calculation.111 While it is true that the MSS-1 amount is dependent

on the relative load responsibility of ETI, that relative change in load responsibility

was factored into the Company’s calculation.112

       Evidence from other parties regarding the MSS-1 costs likewise does not

provide substantial evidence justifying a wholesale disallowance of the third-party

contract costs. Cities, in fact, adopted ETI’s calculation of MSS-1 impacts.113 And

though TIEC argued on one hand that ETI’s MSS-1 expense would increase over

test-year levels,114 the evidence, including TIEC’s, is undisputed that MSS-1 costs

go down as ETI adds new capacity contracts.115 In fact, the MSS-1 costs decreased

during the test year and reached test-year lows during the last two months (when

the new Frontier contract was first put in place).116 TIEC’s recommendations

regarding MSS-1 costs are contrary to reality and all the record evidence. They

certainly do not provide a reasoned basis to reject all of ETI’s proposed increase in

third-party purchased capacity costs.




111
    AR Binder 43, Vol. L (5/3/12 Tr. at 1947).
112
    See AR Binder 35, ETI Exh. 34 (Cooper Direct at 20 of 25 & ETI Exh. 34A RRC-1 [Highly
Sensitive]).
113
    AR Binder 9, Cities Exh. 6 (Nalepa Direct at 17).
114
    AR Binder 41, TIEC Exh. 1 (Pollock Direct at 26).
115
    AR Binder 41, TIEC Exh. 1D (Pollock Direct at 22, Table 1); AR Binder 9, Cities Exh. 6
(Nalepa Direct Attachment KJN-3 at 2 [Highly Sensitive]).
116
    See AR Binder 9, Cities Exh. 6 (Nalepa Direct Attachment KJN-3 at 2 [Highly Sensitive]).
                                            35
                    c.     MSS-4 Costs

      The Commission also found that the impact the purchased capacity contracts

would have on MSS-4 costs (costs of unit-specific purchases from other Entergy

operating companies) was substantially uncertain because the calculation of MSS-4

costs depends on “complex mathematical formulae that utilize numerous

variables.”117 However, as shown in the proposal for decision adopted by the

Commission, the adjusted MSS-4 costs sought by the Company are lower than the

test-year level of MSS-4 costs awarded by the Commission. As the Commission

further acknowledged, “while the purchases pursuant to MSS-4 [from test year to

rate year] remain fairly stable, the third-party purchases will substantially increase,

with a somewhat corresponding decrease for purchases pursuant to MSS-1.”118

      In other words, the Commission recognized that the known and measurable

adjustment to the test-year amount was driven by third-party purchases, not MSS-4

purchases.    The small difference between the test-year and rate-year levels

associated with MSS-4 purchases, under the Commission’s own observations, is

not material to determining the merits of ETI’s proposed purchased power cost

adjustments. In short, alleged uncertainty regarding the rate-year level of MSS-4




117
  AR Binder 7, Item 244 (Order on Rehearing at FOFs 79-82).
118
   AR Binder 5, Item 185 (Proposal for Decision at 100); AR Binder 7, Item 244 (Order on
Rehearing at 1, adopting Proposal for Decision).
                                          36
expense is not a reasonable basis for the Commission to reject ETI’s additional

third-party purchased power expense.

       Even assuming arguendo that the Commission’s rejection of the Company’s

adjustment to MSS-4 expense is material to the resolution of this issue, the

evidence regarding MSS-4 expense does not support rejection of the entire increase

in third-party purchased capacity costs.            Similar to ETI, Cities’ and TIEC’s

adjustments for MSS-4 costs in all but one respect varied only marginally from the

test year. They come nowhere near to offsetting the entire cost of the third-party

contracts.119 Cities and TIEC proposed MSS-4 reductions that were materially

larger than ETI’s120 only because one of ETI’s Arkansas affiliate contracts (the

“WBL” contract) was set to terminate after the test year. Intervenors’ argument

was based on the flawed assumption that ETI would take no action to replace the

WBL contract. To the contrary, the evidence was undisputed that ETI was short of

capacity and in fact extended the very contract in question.121 The dispute over

how much ETI might save in MSS-4 costs does not rationally support a

disallowance of the entire increase for the new purchased capacity contracts



119
    AR Binder 41, TIEC Exh. 1 (Pollock Direct at Exh. JP-1) (Line 4 shows $1.4 million
reduction to test year amount of affiliate contracts)); AR Binder 8, Cities Exh. 4B (Goins Errata
3 Exh. DWG-2 [Highly Sensitive]) (less than $3 million reduction to test-year costs for affiliate
contracts excluding WBL).
120
    $12.7 million and $11.1 million, respectively.
121
    AR Binder 43, Vol. E (4/26/12 Tr. at 687-88 & 696); AR Binder 37, ETI Exh. 47 (Cooper
Rebuttal at 5 of 21); AR Binder 43, Vol. L (5/3/12 Tr. at 1946).
                                               37
      D.     The consequences of the Commission’s decision are extreme
             and unjust.

      The three new third-party purchased power contracts that drive ETI’s

requested adjustment to test-year capacity costs benefit customers tremendously.

They increase the capacity of ETI resources by 618 MW (150 by the Frontier

contract, 225 by the SRMPA contract, and 243 by the half of the Calpine contract

allocated to ETI). They result in substantial fuel savings for customers because of

their diverse fuel resources and efficient heat rates.122 Customers will benefit from

those savings on a dollar-for-dollar basis in fuel reconciliations. While the third-

party owners of the capacity resources profit from the capacity payments ETI must

make, and the retail customers of ETI benefit from the superior heat rates and

resulting fuel savings, the Commission’s order forces the middleman – ETI –to pay

for the capacity with shareholder funds.

      The Commission’s draconian adherence to the test-year data and incorrect

application of the standard for making adjustments to that data are reasons alone to

reverse the decision, because they taint every one of the Commission’s findings

discussed above.     Even disregarding those errors, none of the Commission’s

findings rationally justifies the disallowance of 100 percent of the cost increase

resulting from the three new contracts. Because the Commission did not quantify


122
  AR Binder 35, ETI Exh. 34 (Cooper Direct at 24 of 25); AR Binder 37, ETI Exh. 47 (Cooper
Rebuttal at 7-8 of 21).
                                           38
how much of a disallowance it made upon each individual theory, if this Court

finds any of the findings are unsupported by substantial evidence, it must reverse

the whole disallowance and remand to the Commission for further consideration.

This Court may not decide fact issues the Commission did not. Tex. Gov’t Code

Ann. § 2001.174(1).

III.   The Commission erred in setting ETI’s transmission equalization (MSS-
       2) expense at the test-year level.

       The Commission also erred in refusing to make any adjustment for another

known and measurable increase in ETI’s expenses after the test year. The Entergy

system transmission grid is a large network, the various pieces of which are owned

by individual Entergy operating companies. The network, however, is integrated

and operated for the mutual benefit of all of the Entergy operating companies.123

In any given month, some of the operating companies may be “long” on the

amount of transmission capacity they own. That is, they own a portion of the

transmission capacity that is greater than their share of the overall load placed on

the transmission system. Other operating companies may be “short” on capacity.

The Entergy System Agreement includes a FERC-approved Schedule MSS-2 that

equalizes the ownership costs of certain high-voltage transmission facilities among

the operating companies. The long operating companies receive MSS-2 payments


123
   AR Binder 36, ETI Exh. 39 (Cicio Direct at 15 of 75); AR Binder 43, Vol. C (4/25/12 Tr. at
450); AR Binder 43, Vol. F (4/27/12 Tr. at 793).
                                             39
from the short operating companies for the use of their transmission facilities so

that each pays its fair share of the total ownership costs of the shared system on a

monthly basis.124

       Over the course of the test year, ETI was short, so it paid a total of

$1,753,797 in MSS-2 payments to various other operating companies.125                    But

ETI’s MSS-2 expenses increased at the end of the test year and continued to

increase after the test year.126 ETI anticipated these costs would increase even

more by the rate year because of transmission projects that were planned to go into

service by the rate year.127 ETI calculated that its MSS-2 expenses would be $10.7

million annually by the rate year.128 ETI sought to include that level of its expense

in its rates.

       The ALJs recommended that the Commission disallow any increase in MSS-

2 expense over the test-year level. They found that the increased expenses were

not “known and measurable,” again because the MSS-2 calculation depends on

variables and projections, and because not all the projects ETI included in its




124
    AR Binder 36, ETI Exh. 39 (Cicio Direct at 15 of 75); AR Binder 43, Vol. F (4/27/12 Tr. at
731 & 735-36).
125
    AR Binder 43, Vol. F (4/27/12 Tr. at 724 & 737); AR Binder 9, Cities Exh. 28.
126
    AR Binder 9, Cities Exh. 29.
127
    AR Binder 43, Vol. F (4/27/12 Tr. at 761); AR Binder 37, ETI Exh. 59 (McCulla Rebuttal at
2-3 of 12).
128
    AR Binder 43, Vol. C (4/25/12 Tr. at 452-53); AR Binder 43, Vol. F (4/27/12 Tr. at 738 &
760).
                                             40
calculation were in service during the test year.129 The Commission adopted the

ALJs’ recommendation that only the test-year level of MSS-2 expense should be

included in ETI’s rates.130

          A.     The Commission erred as a matter of law in applying the
                 standard for adjustments to test-year expenses.

          The Commission’s decision is flawed as a matter of law for the same reason

its decision about purchased capacity costs is flawed.                 That is, the goal of

ratemaking is to give the utility a reasonable opportunity to earn a reasonable

return on its investment over and above its reasonable and necessary expenses.

Tex. Util. Code Ann. § 36.051. Commission Rule 25.231 mirrors this principle.

16 Tex. Admin. Code 25.231.              This undertaking cannot lawfully turn on the

manner in which the calculation is made, or on the number of inputs to the

calculation.      The Commission cannot arbitrarily rely upon test-year levels of

expense to the extent they are proven not to represent the level of expense the

utility is reasonably anticipated to bear in the rate year, or that is “apt to prevail in

the future.” City of El Paso, 883 S.W.2d at 188. If a change is known and can

reasonably be measured, the Commission must make it.

          None of the opposing parties’ witnesses refuted that the projects underlying

ETI’s proposed MSS-2 adjustment were already approved and in process, or that


129
      AR Binder 5, Item 185 (Proposal for Decision at 116 & FOFs 87-93).
130
      AR Binder 7, Item 244 (Order on Rehearing at 1 & FOFs 87-94).
                                               41
they will be completed. No intervenor or Staff witness offered any testimony or

evidence casting doubt on the reasonableness of the construction cost estimates.

Their position was simply that if there is any possibility of uncertainty or

variability in the elements of an adjustment to test-year data, it must be denied.

The Commission erred as a matter of law in adopting that standard.

       B.     Additionally, the Commission’s adherence to test-year
              expense levels is unsupported by substantial evidence.

       It is undisputed that ETI’s test-year level of MSS-2 expense was too low.

Every witness testifying on the issue recognized that the test-year amount is too

small and should be updated based on more recent, actual payment information.

ETI proffered evidence that by the time of the hearing, its annualized MSS-2

expenses based upon actual, known, historical investment exceeded test-year

levels by about $6.7 million, and its rate-year MSS-2 expenses would exceed test-

year levels by almost $9 million.131 TIEC witness Pollock annualized the last six

months of the test-year expense, increasing it by a million dollars.132                  Cities

witness Goins also rejected the test-year expense level and instead used a more

recent 12-month period of actual payments, including six months that occurred

after the test year. He recommended the Commission include an annual expense of



131
    AR Binder 43, Vol. C (4/25/12 Tr. at 452-53); AR Binder 43, Vol. F (4/27/12 Tr. at 738, 760,
763, 780, & 783-84).
132
    AR Binder 41, TIEC Exh. 1 (Pollock Direct at 32-33).
                                              42
$4.1 million in ETI’s rates, exceeding the test year by almost $2.5 million.133

Indeed, Cities Exhibit 29 includes the MSS-2 payment for every month from

January 2010 to February 2012. It shows that MSS-2 costs have steadily increased

every month from the last month of the test year, and in fact have doubled since the

last month of the test year.134             No witness testified that the test year was

representative of the expense ETI would bear during the rate year.                         The

Commission’s decision that the test-year level of MSS-2 expense is sufficient is

simply not supported by any evidence in the record.

          Viewing the evidence as a whole, there is no reasonable basis for a

conclusion that the test-year level of $1.7 million is representative of costs apt to

prevail in the future.         The Commission’s ruling is, therefore, unsupported by

substantial evidence and must be reversed.                        Tex. Gov’t Code Ann.

§ 2001.174(b)(2).

                               CONCLUSION AND PRAYER

          For all these reasons, Entergy Texas, Inc. respectfully requests this Court

reverse the district court’s judgment insofar as it affirms the Public Utility

Commission’s order in the respects discussed above.                      ETI requests the Court

remand the case to the Commission for further proceedings consistent with the



133
      AR Binder 8, Cities Exh. 4 (Goins Direct at 21-22).
134
      AR Binder 9, Cities Exh. 29 (Response of ETI to Cities RFI 5-1).
                                                 43
Court’s decision. Entergy Texas, Inc. further requests its costs of court and any

other relief to which it may show itself justly entitled.

                                  Respectfully submitted,


                                    /s/ Marnie A. McCormick
                                  John F. Williams
                                  State Bar No. 21554100
                                  Marnie A. McCormick
                                  State Bar No. 00794264
                                  mmccormick@dwmrlaw.com
                                  DUGGINS WREN MANN & ROMERO, LLP
                                  P. O. Box 1149
                                  Austin, Texas 78767-1149
                                  (512) 744-9300
                                  (512) 744-9399 fax

                                  ATTORNEYS FOR APPELLANT
                                  ENTERGY TEXAS, INC.




                       CERTIFICATE OF COMPLIANCE

        I certify that this document contains 10,765 words in the portions of the
document that are subject to the word limits of Texas Rule of Appellate Procedure
9.4(i), as measured by the undersigned’s word-processing software.


                                          /s/ Marnie A. McCormick
                                          Marnie A. McCormick




                                           44
                                CERTIFICATE OF SERVICE

       The undersigned counsel certifies that the foregoing document was
electronically filed with the Clerk of the Court using the electronic case filing
system of the Court, and that a true and correct copy was served on the following
lead counsel for all parties via electronic service on the 31st day of March, 2015:

Elizabeth R. B. Sterling
Environmental Protection Division
Office of the Attorney General
P. O. Box 12548 (MC 066)
Austin TX 78711-2548
Counsel for Appellee Public Utility Commission of Texas

Rex D. VanMiddlesworth
Benjamin Hallmark
Thompson Knight LLP
98 San Jacinto Blvd., Ste. 1900
Austin TX 78701
Counsel for Intervenor Texas Industrial Energy Consumers

Susan M. Kelley (retired)135
Administrative Law Division
Office of the Attorney General
P. O. Box 12548
Austin TX 78711-2548
Counsel for Intervenor State Agencies

Sara Ferris
Office of Public Utility Counsel
1701 N. Congress Ave., Ste. 9-180
P. O. Box 12397
Austin TX 78711-2397
Counsel for Intervenor Office of Public Utility Counsel




135
      State Agencies have not yet appeared or designated a new lead counsel in this appeal.
                                                 45
Daniel J. Lawton
LAWTON LAW FIRM PC
12600 Hill Country Blvd., Ste. R-275
Austin TX 78738
Counsel for Cities of Anahuac, et al.



                                         /s/ Marnie A. McCormick
                                        Marnie A. McCormick




                                         46
                                APPENDICES

A.   ALJs’ Proposal for Decision in Docket No. 39896

B.   Commission's Order on Rehearing in Docket No. 39896

C.   District Court's Final Judgment

D.   Commission’s Final Order in Docket No. 37744




                                       47
                APPENDIX A

ALJ's Proposal for Decision in Docket No. 39896
                                  SOAH DOCKET NO. XXX-XX-XXXX
                                     PUC DOCKET NO. 39896

APPLICATION OF ENTERGY TEXAS,                                  §           BEFORE THE STATE OFFICE
INC. FOR AUTHORITY TO CHANGE                                   §
RATES, RECONCILE FUEL COSTS,                                   §                                   OF
AND OBTAIN DEFERRED                                            §
ACCOUNTING TREATMENT                                           §          ADMINISTRATIVE HEARINGS

                                      PROPOSAL FOR DECISION

                                          TABLE OF CONTENTS


I.          INTRODUCTION [Germane to Preliminary Order Issue Nos. 1 and 4]........ 1
II.         JURISDICTION AND NOTICE ......................................................................... 2
III.        PROCEDURAL HISTORY ................................................................................. 2
IV.         EXECUTIVE SUMMARY .................................................................................. 4
       A.   Rate Base................................................................................................................ 4
            1.         Capital Investment .................................................................................... 4
            2.         Hurricane Rita Regulatory Asset ............................................................ 4
            3.         Prepaid Pension Asset Balance ................................................................ 5
            4.         FIN 48 Tax Adjustment ............................................................................ 5
            5.         Cash Working Capital .............................................................................. 5
            6.         Self-Insurance Storm Reserve ................................................................. 5
            7.         Coal Inventory........................................................................................... 5
            8.         Spindletop Gas Storage Facility .............................................................. 5
            9.         Short Term Assets ..................................................................................... 6
            10.        Acquisition Adjustment ............................................................................ 6
            11.        Capitalized Incentive Compensation ...................................................... 6
       B.   Rate of Return and Capital Structure ................................................................ 6
       C.   Cost of Service ....................................................................................................... 7
            1.         Purchased Power Capacity Expense ....................................................... 7
            2.         Transmission Equalization (MSS-2) Expense ........................................ 7
            3.         Depreciation Expense ............................................................................... 7
            4.         Labor Costs................................................................................................ 7
SOAH DOCKET NO. XXX-XX-XXXX                          TABLE OF CONTENTS                                                         PAGE II
PUC DOCKET NO. 39896


             5.         Interest on Customer Deposits................................................................. 8
             6.         Property (Ad Valorem) Tax Expense ...................................................... 9
             7.         Advertising, Dues, and Contributions..................................................... 9
             8.         Other Revenue Related Adjustments ...................................................... 9
             9.         Federal Income Tax .................................................................................. 9
             10.        River Bend Decommissioning Expense ................................................... 9
             11.        Self-Insurance Storm Reserve Expense .................................................. 9
             12.        Spindletop Gas Storage Facility ............................................................ 10
      D.     Affiliate Transactions ......................................................................................... 10
      E.     Jurisdictional Cost Allocation............................................................................ 10
      F.     Class Cost Allocation .......................................................................................... 11
             1.         Renewable Energy Credit Rider............................................................ 11
             2.         Class Cost Allocation .............................................................................. 11
             3.         Revenue Allocation ................................................................................. 12
             4.         Rate Design .............................................................................................. 12
      G.     MISO Transition ................................................................................................. 14
V.           RATE BASE [Germane to Preliminary Order Issue Nos. 4, 10, and 16] ...... 14
      A.     Capital Investment [Germane to Preliminary Order Issue No. 17] ............... 14
      B.     Hurricane Rita Regulatory Asset ...................................................................... 15
      C.     Prepaid Pension Asset Balance .......................................................................... 23
      D.     FIN 48 Tax Adjustment ...................................................................................... 26
      E.     Cash Working Capital ........................................................................................ 30
             1.         The Revenue Lag Component of the Lead-Lag Study ........................ 31
             2.         The Expense Lead Component of the Lead-Lag Study ....................... 39
      F.     Self-Insurance Storm Reserve [Germane to Preliminary Order Issue
             No. 5] .................................................................................................................... 45
             1.         The Effect of Prior Settled Cases........................................................... 46
             2.         OPC’s Proposed Adjustment ................................................................. 49
             3.         1997 Ice Storm ......................................................................................... 54
             4.         Jurisdictional Separation Plan Allocation ............................................ 57
             5.         $50,000 Reserve Threshold .................................................................... 58
             6.         Hurricane Rita Regulatory Asset .......................................................... 60
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             7.         Conclusion ............................................................................................... 60
       G.    Coal Inventory..................................................................................................... 61
       H.    Spindletop Gas Storage Facility ........................................................................ 63
       I.    Short Term Assets ............................................................................................... 68
       J.    Acquisition Adjustment ...................................................................................... 69
       K.    Capitalized Incentive Compensation ................................................................ 71
VI.          RATE OF RETURN [Germane to Preliminary Order Issue Nos. 4 and
             11] ......................................................................................................................... 73
       A.    Capital Structure ................................................................................................ 73
       B.    Return on Equity................................................................................................. 73
             1.         Proxy Group ............................................................................................ 74
             2.         DCF Analysis ........................................................................................... 76
             3.         Risk Premium Analysis .......................................................................... 83
             4.         Comparable Earnings............................................................................. 88
             5.         CAPM Analysis ....................................................................................... 90
             6.         ALJs’ Analysis......................................................................................... 93
       C.    Cost of Debt ......................................................................................................... 95
       D.    Overall Rate of Return ....................................................................................... 95
VII.         OPERATING EXPENSES [Germane to Preliminary Order Issue Nos. 2,
             3, 4, and 16] .......................................................................................................... 95
       A.    Purchased Power Capacity Expense [Germane to Supplemental
             Preliminary Order Issue No. 1] ......................................................................... 95
             1.         The Sources of ETI’s Purchased Power................................................ 95
             2.         ETI’s Request Regarding PPCCs .......................................................... 99
             3.         Staff and Intervenors’ Opposition to ETI’s PPCCs Proposal .......... 101
             4.         The Intervenors’ Recommendations Regarding PPCCs ................... 106
             5.         The ALJs’ Analysis Regarding PPCCs ............................................... 108
       B.    Transmission Equalization (MSS-2) Expense ................................................ 110
       C.    Depreciation Expense [Germane to Preliminary Order Issue No. 12] ........ 117
             1.         Terminology and Methodology............................................................ 118
             2.         Production Plant ................................................................................... 125
             3.         Transmission Plant ............................................................................... 132
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PUC DOCKET NO. 39896


             4.         Distribution Plant ................................................................................. 140
             5.         General Plant......................................................................................... 154
             6.         Fully Accrued Depreciation ................................................................. 160
             7.         Other Depreciation Issues – Accumulated Provision for
                        Depreciation .......................................................................................... 161
        D.   Labor Costs........................................................................................................ 163
             1.         Payroll and Related Adjustments ........................................................ 163
             2.         Incentive Compensation ....................................................................... 165
             3.         Compensation and Benefits Levels ...................................................... 175
             4.         Non-Qualified Executive Retirement Benefits ................................... 177
             5.         Employee Relocation Costs .................................................................. 179
             6.         Executive Perquisites ............................................................................ 180
        E.   Interest on Customer Deposits......................................................................... 181
        F.   Property (Ad Valorem) Tax Expense .............................................................. 181
        G.   Advertising, Dues, and Contributions............................................................. 185
        H.   Other Revenue-Related Adjustments ............................................................. 185
        I.   Federal Income Tax .......................................................................................... 185
        J.   River Bend Decommissioning Expense ........................................................... 186
        K.   Self-Insurance Storm Reserve Expense [Germane to Preliminary Order
             Issue No. 5]......................................................................................................... 188
        L.   Spindletop Gas Storage Facility ...................................................................... 193
VIII.        AFFILIATE TRANSACTIONS [Germane to Preliminary Order Issue
             No. 3] .................................................................................................................. 194
        A.   Large Industrial & Commercial Sales Reallocation ...................................... 199
        B.   Administration Costs ........................................................................................ 201
        C.   Customer Service Operations Class ................................................................ 202
             1.         Projects F3PCR29324 (Revenue Assurance - Adm.), F3PCR53095
                        (Headquarter’s Credit & Collect), F3PCR73380 (Credit
                        Systems), and F3PCR73458 (Credit Call Outsourcing) .................... 202
             2.         Projects F3PCR73381 (Customer Svc Cntr Credit Desk),
                        F3PCR73390 (Customer Svs Ctl - Entergy Bus), and
                        F3PCR73403 (Customer Issue Resolution – ES) ............................... 203
        D.   Distribution Operations Class ......................................................................... 203
             1.         Project F5PCDW0200 (Lineman’s Rodeo Expenses) ........................ 204
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             2.        Projects F3PCTJGUSE (Joint Use With Third Party – E) and
                       F3PCTJTUSE (Joint Use With Third Parties – A)............................ 204
      E.     Energy and Fuel Management Class .............................................................. 205
             1.        Project F3PCWE0140 (EMO Regulatory Affairs) ............................ 205
             2.        Projects F3PPSPE003 (SPO Summer 2009 RFP Expense),
                       F3PPSPE003 (SPO Summer 2009 RFP Expense), F3PPSPE004
                       (SPO Summer09RFP IM & Propslsubmt), and F3PPWET303
                       (SPO2008 Winter Westn RegionRFP-IM) ......................................... 206
             3.        Project F3PCCSPSYS (System Planning and Strategic) .................. 207
      F.     Environmental Service Class ........................................................................... 207
      G.     Federal PRG Affairs Class ............................................................................... 209
             1.        Project F5PPSPE044 (PMO Support Initiative-System) .................. 209
             2.        Project F3PPUTLDER (Utility Derivatives Compliance) ................. 210
             3.        Project F3PCSYSRAF (System Regulatory Affairs-Federal) .......... 211
      H.     Financial Services Class ................................................................................... 214
             1.        Projects F3PCF05700 (Corporate Planning & Analysis),
                       F3PCF21600 (Corp Rptg Analysis & Policy), F3PCFF1000
                       (Financial Forecasting), F3PPADSENT (Analytic/Decision
                       Support-Entergy), and F3PPSPSENT (Strategic Planning Svcs-
                       Entergy) ................................................................................................. 214
             2.        Projects F3PCF20990 (Operations Exec VP & CFO) and
                       F3PCFF1001 (OCE Support)............................................................... 215
             3.        Project F3PCR73345 (Quick Payment Center, Adm) ....................... 216
             4.        Project F3PCF23936 (Manage Cash) .................................................. 217
      I.     Human Resources Class ................................................................................... 218
             1.        Project F3PCHRCCSM (HR Competitive Compensation) .............. 218
             2.        Projects (Non-Qualified Post-Retirement) and F5PPZNQBDU
                       (Non-Qual Pension/Benf-Dom Utl)...................................................... 219
      J.     Information Technology Class ......................................................................... 219
             1.         (Evaluated Receipts Settlement) ......................................................... 220
             2.        Project F3PCFX3555 (BOD/Executive Support) ............................... 220
      K.     Internal and External Communications Class ............................................... 221
      L.     Legal Services Class .......................................................................................... 222
             1.        Project F3PPCASHCT (Contractual Alternative/Cashpo) .............. 223
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PUC DOCKET NO. 39896


             2.        Project F5PCZLDEPT (Supervision & Support – Legal)................. 223
             3.        Project F3PCF99180 (Corp. Compliance Tracking Sys) .................. 223
             4.        Projects F3PPINVDOJ (DOJ Anti Trust Investigation) and
                       F3PPTDHY19 (Dept. of Justice Investigation) .................................. 224
             5.        Project F3PCE01601 (Ferc - Access Transmission) ......................... 226
             6.        Project F3PCERAKTL (RAKTL Patent Matter) ............................. 227
             7.        Project F3PPEASTIN (Willard Eastin et al.) ..................................... 228
             8.        Project F3PPTCGS11 (TX Docket Competitive Generation) .......... 229
             9.        Project F5PCE13759 (Jenkins Class Action Suit) ............................. 230
             10.       Project F3PCSYSAGR (System Agreement-2001) ............................ 231
             11.       Project F3PCCDVDAT (Corporate Development Data Room) ....... 232
             12.       Project F3PPWET302 (SPO 2008 Winter Western Region) ............ 233
             13.       Project F3PPWET308 (SPO Calpine PPA/Project Houston) ........... 234
      M.     Other Expenses Class ....................................................................................... 235
             1.        Projects F3PCSPETEI (Entergy-Tulane Energy Institute) and
                       F5PPKATRPT (Storm Cost Processing & Review) .......................... 235
             2.        Project F3PCC08500 (Executive VP, Operations)............................. 236
             3.        Projects F3PPBFMESI (ESI Function Migration Relocation),
                       F3PPBFRESI (ESI Business Function ), F3PPDRPESI (ESI
                       Disaster Recovery Plan Charge), F5PPBFMREL (Business
                       Function Migration Employee), F5PPBFRREL (Business
                       Function Relocation), F5PPBFRSEV (Business Function
                       Relocation Severance), F5PPDRPREL (Disaster Recovery Plan
                       Relocation), and F5PPETXRFI (2009 Texas Ike Recovery Filing) .. 236
      N.     Regulatory Services Class ................................................................................ 238
      O.     Retail Operations Class .................................................................................... 239
             1.        Project F5PPICCIMG (ICC – “Image” Message) ............................. 240
             2.        Projects F3PPR56640 (Wholesale - EGS-TX) and F3PPR56920
                       (Wholesale - All Jurisdictions) ............................................................. 240
      P.     Supply Chain Class ........................................................................................... 241
      Q.     Transmission and Distribution Support Class ............................................... 242
      R.     Tax Services Class ............................................................................................. 244
      S.     Transmission Operations Class ....................................................................... 245
      T.     Treasury Operations Class .............................................................................. 246
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PUC DOCKET NO. 39896


      U.     Utility and Executive Management Class ....................................................... 249
IX.          JURISDICTIONAL COST ALLOCATION [Germane to Preliminary
             Order Issue No. 13] ........................................................................................... 250
      A.     A&E 4CP ........................................................................................................... 251
      B.     12CP ................................................................................................................... 252
X.           CLASS COST ALLOCATION AND RATE DESIGN [Germane to
             Preliminary Order Issue No. 1] ....................................................................... 255
      A.     Renewable Energy Credit Rider [Germane to Preliminary Order Issue
             No. 19] ................................................................................................................ 255
             1.         ETI’s Proposed Cost Recovery ............................................................ 255
             2.         Opposition to ETI’s Proposal .............................................................. 256
             3.         ETI’s Response ...................................................................................... 260
             4.         ALJs’ Analysis....................................................................................... 261
      B.     Class Cost Allocation [Germane to Preliminary Order Issue No. 14] ......... 262
             1.         Municipal Franchise Fees .................................................................... 262
             2.         Miscellaneous Gross Receipts Taxes ................................................... 267
             3.         Capacity-Related Production Costs .................................................... 268
             4.         Transmission Costs ............................................................................... 273
      C.     Revenue Allocation ........................................................................................... 274
             1.         Argument for Moving Rates to Cost ................................................... 275
             2.         Argument for Gradualism ................................................................... 278
             3.         ALJs’ Recommendation ....................................................................... 281
      D.     Rate Design [Germane to Preliminary Order Issue Nos. 15, 18, and 20] .... 282
             1.         Lighting and Traffic Signal Schedules ................................................ 283
             2.         Demand Ratchet .................................................................................... 287
             3.         Large Industrial Power Service (LIPS) .............................................. 295
             4.         Schedulable Intermittent Pumping Service (SIPS)............................ 299
             5.         Standby Maintenance Service (SMS) .................................................. 303
             6.         Additional Facilities Charge (AFC) .................................................... 310
             7.         Large General Service (LGS) .............................................................. 313
             8.         General Service (GS) ............................................................................ 315
             9.         Residential Service (RS) ....................................................................... 315
SOAH DOCKET NO. XXX-XX-XXXX                         TABLE OF CONTENTS                                                     PAGE VIII
PUC DOCKET NO. 39896


XI.          FUEL RECONCILIATION [Germane to Preliminary Order Issue
             Nos. 21-31] ......................................................................................................... 319
        A.   Spindletop Gas Storage Facility ...................................................................... 324
        B.   Use of Current Line Losses for Fuel Cost Allocation .................................... 325
        C.   ETI’s Special Circumstances Request ............................................................ 326
XII.         OTHER ISSUES ............................................................................................... 327
        A.   MISO Transition Expenses [Germane to Preliminary Order Issue
             Nos. 6-8 and Docket No. 39741 Preliminary Order Issue Nos. 1-9] ............. 327
             1.         Deferred Accounting............................................................................. 329
             2.         Base Rate Recovery............................................................................... 336
        B.   TCRF Baseline [Germane to Supplemental Preliminary Order Issue
             No. 2] .................................................................................................................. 338
        C.   DCRF Baseline [Germane to Supplemental Preliminary Order Issue
             No. 2] .................................................................................................................. 338
        D.   Purchased Power Capacity Cost Baseline [Germane to Supplemental
             Preliminary Order Issue No. 1] ....................................................................... 339
XIII.        CONCLUSION ................................................................................................. 341
XIV.         PROPOSED FINDINGS OF FACT, CONCLUSIONS OF LAW, AND
             ORDERING PARAGRAPHS .......................................................................... 341
        A.   Findings of Fact ................................................................................................. 341
        B.   Conclusions of Law ........................................................................................... 364
        C.   Proposed Ordering Paragraphs ...................................................................... 366

List of Acronyms and Defined Terms

Attachment A
                List of Acronyms and Defined Terms

TERM                DEFINITION
12CP                12 Coincident Peak
A&E 4CP             Average and Excess, 4 Coincident Peak
A&P                 Average and Single Coincident Peak
ADFIT               Accumulated Deferred Federal Income Tax
AFC                 Additional Facilities Charge
AFUDC               Allowance for Funds Used During Construction
ALJs                Administrative Law Judges
BCII/U3             Big Cajun II, Unit 3
Brazos              Brazos Electric Cooperative, Inc.
Calpine             Calpine Energy Services
                    Contract for the purchase of 485 MW of capacity from
Carville Contract   Calpine’s Carville Energy Center
CAPM                Capital Asset Pricing Model
CenterPoint         CenterPoint Energy Houston Electric, LLC
CGS                 Competitive Generation Service
CI                  Conformance Index
                    Anahuac, Beaumont, Bridge City, Cleveland, Conroe,
                    Dayton, Groves, Houston, Huntsville, Montgomery,
                    Navasota, Nederland, Oak Ridge North, Orange, Pine
                    Forest, Rose City, Pinehurst, Port Arthur, Port Neches,
                    Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and
Cities              West Orange, Texas
Commission          Public Utility Commission of Texas
Company             Entergy Texas, Inc.
CP                  Coincident Peak
CWIP                Construction Work in Progress
DCF                 Discounted Cash Flow
DCRF                Distribution Cost Recovery Factor
DOE                 United States Department of Energy
DOJ                 United States Department of Justice
EAI                 Entergy Arkansas, Inc.
EA WBL              2009 Contract between ETI and EAI for Wholesale Base
Contract            Load Resources
EGSI                Entergy Gulf States, Inc., predecessor to ETI
EGSL                Entergy Gulf States Louisiana, LLC
ELL                 Entergy Louisiana, Inc.
EMI                 Entergy Mississippi, Inc.
Enbridge            Long-term Gas Supply Contract between ETI and Enbridge
Contract            Pipeline, L.P.
ENOI                Entergy New Orleans, Inc.
Entergy             Entergy Corporation
TERM             DEFINITION
ESI              Entergy Services, Inc.
ETEC             East Texas Electric Cooperative, Inc.
ETI              Entergy Texas, Inc.
FAS 106          FASB Statement No. 106
FASB             Financial Accounting Standards Board
FERC             Federal Energy Regulatory Commission
FIN 48           Financial Interpretation Number 48
GAAP             Generally Accepted Accounting Principles
GDP              Gross Domestic Product
GS               General Service
GSU              Gulf States Utilities Company
Iowa Curves      Various Known Patterns of Industrial Asset Mortality Rates
IRS              Internal Revenue Service
ISB              Intra-System Bill
                 Class action lawsuit filed in Texas district court in 2003 on
Jenkins Class    behalf of all Texas retail customers served by ETI’s
Action           predecessor-in-interest, EGSI
Kroger           The Kroger Co.
kW               Kilowatt
kWh              Kilowatt-hour
LED              Light Emitting Diode
LGS              Large General Service
LIPS             Large Industrial Power Service
MFF              Municipal Franchise Fees
MGRT             Miscellaneous Gross Receipts Tax
MISO             Midwest Independent Transmission System Operator, Inc.
MSS-2            Schedule MSS-2 of the Entergy System Agreement
MW               Megawatt
Moody’s          Moody’s Investors Service
MWh              Megawatt-hour
NARUC            National Association of Regulatory Utility Commissioners
Nelson           Nelson 6, a 550 MW Unit located in Westlake, Louisiana
O&M              Operations and Maintenance
OATT             Open Access Transmission Tariff
OPC              Office of Public Utility Counsel
PFD              Proposal for Decision
PPCCs            Purchased Power Capacity Costs
PPR              Purchased Power Rider
PUC              Public Utility Commission of Texas
PURA             Public Utility Regulatory Act
Rate Year        June 1, 2012, through May 31, 2013
Reconciliation
Period           July 1, 2009, through June 30, 2011
TERM             DEFINITION
RECs             Renewable Energy Credits
Reserve          Strategic Petroleum Reserve
River Bend       River Bend Nuclear Generating Station Unit No. 1
ROE              Return on Equity
RRC              Railroad Commission of Texas
RS               Residential Service
RTO              Regional Transmission Organization
S&P              Standard & Poor’s
SFAS             Statement of Financial Accounting Standards
SIPS             Schedulable Intermittent Pumping Service
SMS              Standby Maintenance Service
SOAH             State Office of Administrative Hearings
Spindletop
Facility         Spindletop Gas Storage Facility
SRMPA            Sam Rayburn Municipal Power Agency
Staff            Staff of the Public Utility Commission of Texas
State Agencies   State of Texas State Agencies
T&D              Transmission and Distribution
TCRF             Transmission Cost Recovery Factor
Test Year        July 1, 2010, through June 30, 2011
TIEC             Texas Industrial Energy Consumers
Value Line       Value Line Investment Survey
Wal-Mart         Wal-Mart Stores, LLC, and Sam’s East, Inc.
Zacks            Zacks Investment Service
                                   SOAH DOCKET NO. XXX-XX-XXXX
                                      PUC DOCKET NO. 39896

APPLICATION OF ENTERGY TEXAS,                            §         BEFORE THE STATE OFFICE
INC. FOR AUTHORITY TO CHANGE                             §
RATES, RECONCILE FUEL COSTS,                             §                           OF
AND OBTAIN DEFERRED                                      §
ACCOUNTING TREATMENT                                     §        ADMINISTRATIVE HEARINGS


                                      PROPOSAL FOR DECISION

         I.   INTRODUCTION [Germane to Preliminary Order Issue Nos. 1 and 4]

        Entergy Texas, Inc. (ETI or the Company) is an investor-owned electric utility with a retail
service area located in southeastern Texas. ETI serves retail and wholesale electric customers in
Texas. As of June 30, 2011, ETI served approximately 412,000 Texas retail customers. The Federal
Energy Regulatory Commission (FERC) regulates ETI’s wholesale electric operations.


        On November 28, 2011, ETI filed an application requesting approval of: (1) a proposed
increase in annual base rate revenues of approximately $111.8 million over adjusted revenues for the
period beginning July 1, 2010, and ending June 30, 2011 (Test Year); (2) a set of proposed tariff
schedules presented in the Electric Utility Rate Filing Package for Generating Utilities
accompanying ETI’s application and including new riders for recovery of costs related to purchased
power capacity and renewable energy credit requirements; (3) a request for final reconciliation of
ETI’s fuel and purchased power costs for the reconciliation period from July 1, 2009, to June 30,
2011 (Reconciliation Period); and (4) certain waivers to the instructions in Rate Filing Package
Schedule V accompanying ETI’s application. The rate year for ETI’s proposed changes is June 1,
2012, through May 31, 2013 (Rate Year).1 On April 13, 2012, adjusted its request for a proposed
increase in annual base rate revenues to approximately $104.8 million over adjusted Test Year
revenues.


1
   During the hearing the parties used the term “Rate Year” to refer to the period June 2012 through May
2013. This was intended to represent the first 12 months of the rates adopted in this case. However, the rates
in this case will not go into effect (as temporary rates) until at least June 30, 2012. Nevertheless, for purposes
of this PFD, Rate Year will refer to the period June 2012 through May 2013.
SOAH DOCKET NO. XXX-XX-XXXX                PROPOSAL FOR DECISION                                 PAGE 2
PUC DOCKET NO. 39896


                              II.      JURISDICTION AND NOTICE

          The Public Utility Commission of Texas (Commission or PUC) has jurisdiction over ETI and
this rate case application pursuant to Public Utility Regulatory Act (PURA) §§ 14.001, 32.001,
33.002, and 35.004. The State Office of Administrative Hearings (SOAH) has jurisdiction over the
contested case hearing, including the preparation of the proposal for decision (PFD) pursuant to
PURA § 14.053 and Tex. Gov’t Code § 2003.049(b). Those municipalities in ETI’s service area that
have not surrendered jurisdiction to the Commission continue to have exclusive original jurisdiction
over ETI’s rates, operations, and services in their respective municipalities pursuant to PURA
§ 33.001. When ETI filed its application with the Commission, it also filed the application with its
original jurisdiction cities. Pursuant to PURA §§ 32.001(b), 33.051, and 33.053, ETI appealed the
actions of the original jurisdiction cities to the Commission and had those appeals consolidated with
this docket.


          ETI’s notice of its application and notice of the hearing were not contested and, therefore, do
not require further discussion but will be addressed in the proposed findings of fact and conclusions
of law.


                                III.    PROCEDURAL HISTORY

          As noted above, ETI filed its application and rate filing package on November 28, 2011. On
November 29, 2011, the Commission referred this proceeding to SOAH. On December 19, 2011,
the Commission issued its Preliminary Order setting forth 31 issues to be addressed in this
proceeding. On January 19, 2012, the Commission issued a Supplemental Preliminary Order listing
two additional issues to be considered and stating that ETI’s request for a purchased power cost
recovery rider should not be addressed in this docket.


          On September 2, 2011, ETI filed an application requesting authority to defer accounting
related to its proposed transition to membership in the Midwest Independent Transmission System
Operator, Inc. (MISO). This proceeding was docketed as Docket No. 39741. On November 22,
2011, the Commission issued its Preliminary Order in Docket No. 39741 addressing certain
SOAH DOCKET NO. XXX-XX-XXXX               PROPOSAL FOR DECISION                                   PAGE 3
PUC DOCKET NO. 39896


threshold legal/policy questions and setting forth nine issues to be addressed in the proceeding. On
December 20, 2011, Docket No. 39741 was consolidated into this docket for all purposes.


        The following entities were granted intervenor status in this case: Texas Industrial Energy
Consumers (TIEC); State of Texas State Agencies (State Agencies); Office of Public Utility Counsel
(OPC); the Cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Dayton, Groves,
Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest,
Rose City, Pinehurst, Port Arthur, Port Neches, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor,
and West Orange (Cities); The Kroger Co. (Kroger); Wal-Mart Stores, LLC, and Sam’s East, Inc.
(Wal-Mart); East Texas Electric Cooperative, Inc. (ETEC); and the United States Department of
Energy (DOE).


        The hearing on the merits convened before SOAH Administrative Law Judges (ALJs)
Thomas H. Walston, Steven D. Arnold, and Hunter Burkhalter on April 24, 2012, and continued
through May 4, 2012. The record remained open for the filing of post-hearing briefs and proposed
finds of fact and conclusions of law. On June 8, 2012, the parties filed proposed finds of fact and
conclusions of law and the record closed. As permitted by P.U.C. PROC. R. 22.261(a), ALJ Lilo D.
Pomerleau read the record and joined in writing the PFD. Number running began on June 26, 2012,
and Staff returned the final numbers to the ALJs on July 3, 2012. The parties requested that the ALJs
submit their PFD so the Commission could consider the matter at its July 27, 2012, open meeting.


        The following is a list of the parties who participated in the hearing and their counsel:


     PARTIES                       REPRESENTATIVES
     ETI                           Steven H. Neinast, Casey Wren, and John F. Williams2
     Cities                        Daniel J. Lawton, Stephen Mack, and Molly Mayhall
     TIEC                          Rex. D. VanMiddlesworth, Meghan Griffiths, and James
                                   Nortey
     State of Texas                Susan Kelley
     OPC                           Sara J. Ferris
     DOE                           Steven A. Porter

2
  Several other attorneys appeared on behalf of ETI. The ALJs listed only the three attorneys who appeared
throughout the hearing.
SOAH DOCKET NO. XXX-XX-XXXX               PROPOSAL FOR DECISION                                PAGE 4
PUC DOCKET NO. 39896


      PARTIES                        REPRESENTATIVES
      Kroger                         Kurt J. Boehm
      Wal-Mart                       Rick D. Chamberlain
      Staff                          Scott Smyth, Joseph Younger, Jacob J. Lawler, and Jason
                                     Haas



                               IV.     EXECUTIVE SUMMARY

         ETI proposed an overall increase of approximately $104.8 million. The ALJs recommend an
overall rate increase for ETI of $16.4 million, as shown on the schedules attached to this PFD. With
respect to ETI’s request to reconcile fuel and purchased power costs during the Reconciliation
Period, the ALJs recommend approval without change. Attachment A contains the schedules
provided by Commission Staff reflecting the ALJs’ recommendations. On issues of particular
significance, the ALJs’ recommendations are set forth below.


A.       Rate Base

         1. Capital Investment

         ETI’s capital additions closed to plant in service between July 1, 2009, and June 30, 2011,
were prudently incurred and are used and useful in providing service to ETI’s customers.


         2. Hurricane Rita Regulatory Asset

         The appropriate calculation of the Hurricane Rita regulatory asset should begin with the
amount claimed by ETI in Docket No. 37744,3 less amortization accruals to the end of the Test Year
in the present case, and less the amount of additional insurance proceeds received by ETI after the
conclusion of Docket No. 37744. This produces a remaining balance of $15,175,563, which should
remain in rate base as a regulatory asset, applying a five-year amortization rate that commenced
August 15, 2010. Further, the Hurricane Rita regulatory asset should not be moved to the storm
insurance reserve.


3
    Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket
SOAH DOCKET NO. XXX-XX-XXXX            PROPOSAL FOR DECISION                              PAGE 5
PUC DOCKET NO. 39896


        3. Prepaid Pension Asset Balance

        The construction work in progress (CWIP)-related portion of ETI’s pension asset
($25,311,236 out of the total asset) should be excluded from the asset, but accrue allowance for
funds used during construction.


        4. FIN 48 Tax Adjustment

        The Commission should find that $4,621,778 (representing ETI’s full FIN 48 Liability of
$5,916,461 less the $1,294,683 cash deposit ETI has made with the Internal Revenue Service (IRS)
for the FIN 48 Liability) should be added to ETI’s ADFIT and thus be used to reduce ETI’s rate
base.


        5. Cash Working Capital

        The ALJs recommend no changes to ETI’s cash working capital.


        6. Self-Insurance Storm Reserve

        The Commission should approve ETI’s Test Year-end storm reserve balance of negative
$59,799,744.


        7. Coal Inventory

        The full value of ETI’s coal inventory was reasonable and should be included in rate base.


        8. Spindletop Gas Storage Facility

        The Spindletop Gas Storage Facility (Spindletop Facility) is a used and useful facility
providing reliability and swing flexibility to ETI’s customers at a reasonable price and should be
included in rate base.




No. 37744 (Dec. 13, 2010).
SOAH DOCKET NO. XXX-XX-XXXX             PROPOSAL FOR DECISION                               PAGE 6
PUC DOCKET NO. 39896


        9. Short Term Assets

        The ALJs recommend Staff’s proposal to include the following amounts in rate base:
prepayments at $8,134,351 ($916,313 more than ETI’s request); materials and supplies at
$29,285,421 ($32,847 more than ETI’s request); and fuel inventory at $52,693,485 ($1,066,490 less
than ETI’s request).


        10. Acquisition Adjustment

        The $1,127,778 incurred by ETI in internal acquisition costs associated with the purchase of
the Spindletop Facility was reasonable, necessary, properly incurred, and should be included in rate
base.


        11. Capitalized Incentive Compensation

        The Test Year for ETI’s prior ratemaking proceeding ended on June 30, 2009. The
reasonableness of ETI’s capital costs (including capitalized incentive compensation) was dealt with
by the Commission in that proceeding and is not at issue here. Thus, exclusion of capitalized
incentive compensation that is financially-based can only be made for incentive costs that ETI
capitalized during the period from July 1, 2009 (the end of the prior Test Year) through June 30,
2010 (the commencement of the current Test Year).


B.      Rate of Return and Capital Structure

        The ALJs recommend a return on equity (ROE) of 9.80 percent; a cost of debt of
6.74 percent; a capital structure comprised of 50.08 percent debt and 49.92 percent common equity;
and an overall rate of return of 8.27 percent. This is a downward adjustment to ETI’s request for a
10.60 percent ROE, and no change to ETI’s 6.74 percent cost of debt and 50.08/49.92 capital
structure. It compares to Staff’s proposed 9.60 percent ROE; OPC’s proposed 9.30 percent ROE;
TIEC’s proposed 9.50 percent ROE; Cities’ proposed 9.50 percent ROE; and State Agencies’
proposed 9.30 percent ROE. No party opposed ETI’s proposed 6.74 percent cost of debt or its
proposed 50.08/49.92 capital structure.
SOAH DOCKET NO. XXX-XX-XXXX            PROPOSAL FOR DECISION                             PAGE 7
PUC DOCKET NO. 39896


C.     Cost of Service

       1. Purchased Power Capacity Expense

       ETI’s purchased power capacity costs should be set at the amount of the Company’s Test
Year level, which is $245,432,884.


       2. Transmission Equalization (MSS-2) Expense

       ETI should recover only the amount of expenses under Schedule MSS-2 of the Entergy
System Agreement it paid in the Test Year, $1,753,797.


       3. Depreciation Expense

       The interim retirements methodology should not be adopted. The values proposed by ETI
should be adopted except for the following:


       Service Lives:
       Account 364-40 R1.
       Account 368-33 L0.5.

       Net Salvage:
       Production Plant- negative 5 percent.
       Account 354-negative 5 percent
       Account 361-negative 5 percent.
       Account 362-negative 10 percent.
       Account 368-negative 5 percent.
       Account 369.1-negative 10 percent.
       Account 369.2-negative 10 percent.


       4. Labor Costs

           ¾ Payroll and Related Adjustments

       The Commission should accept: (1) the payroll adjustments proposed in the ETI application;
and (2) the further payroll adjustments proposed by Staff as corrected by ETI.
SOAH DOCKET NO. XXX-XX-XXXX             PROPOSAL FOR DECISION                               PAGE 8
PUC DOCKET NO. 39896


           ¾ Incentive Compensation

       ETI should not be entitled to recover its financially based incentive compensation costs.
Thus, the ALJs recommend removing $6,196,037 from ETI’s requested operation and maintenance
(O&M) expenses. Additionally, an additional reduction should be made to account for the FICA
taxes that ETI would have paid as a result of those costs.


           ¾ Compensation and Benefit Levels

       ETI met its burden to prove the reasonableness of its base pay and incentive package costs.
It is reasonable to view market price for these categories of costs as lying within a range of +/-
10 percent of median, rather than being a single point along a spectrum. As to both base pay and the
incentive package, ETI has proven that its costs fall within such an acceptable range. Accordingly,
the ALJs recommend rejecting the adjustments sought by Cities.


           ¾ Nonqualified Executive Retirement Benefits

       The ALJs recommend an adjustment to remove $2,114,931, representing the full costs
associated with ETI’s non-qualified executive retirement benefits.


           ¾ Employee Relocation Costs

       The Commission should allow ETI’s relocation expenses.


           ¾ Executive Perquisites

       The ALJs recommend an adjustment to remove $40,620, representing the full cost of ETI’s
executive perquisite costs.


       5. Interest on Customer Deposits

       The ALJs recommend using the active customer deposits amount of $35,872,476 and the
2012 interest rate, which produces a recommended interest expense of $43,047 ($35,872,476
multiplied by .12 percent).
SOAH DOCKET NO. XXX-XX-XXXX             PROPOSAL FOR DECISION                                PAGE 9
PUC DOCKET NO. 39896


       6. Property (Ad Valorem) Tax Expense

       ETI’s property tax burden should be adjusted upward by applying the effective tax rate of
0.007435784 for the calendar year 2011 to the final, adopted Test Year-end plant in service value for
ETI.


       7. Advertising, Dues, and Contributions

       The ALJs recommend an adjustment to remove $12,800 from ETI’s costs of advertising,
dues and contributions.


       8. Other Revenue Related Adjustments

       These amounts were determined through number running and are reflected in Attachment A.


       9. Federal Income Tax

       The Commission should adopt ETI’s proposal on federal income taxes.


       10. River Bend Decommissioning Expense

       ETI’s annual decommissioning revenue requirement should reflect the most current
calculation of $1,126,000. Therefore, an adjustment of $893,000 to the pro forma cost of service is
needed to reflect the difference between the requested level for decommissioning costs of
$2,019,000 and the recommended level of $1,126,000.


       11. Self-Insurance Storm Reserve Expense

       The Commission should approve a total annual accrual of $8,270,000, comprised of an
annual accrual of $4,400,000 to provide for average annual expected storm losses, plus an annual
accrual of $3,870,000 for 20 years to restore the reserve from its current deficit. The ALJs
recommend approval of ETI’s proposed target reserve of $17,595,000. The Commission should
require ETI to continue recording its annual accrual until modified by future Commission orders.
SOAH DOCKET NO. XXX-XX-XXXX            PROPOSAL FOR DECISION                             PAGE 10
PUC DOCKET NO. 39896


       12. Spindletop Gas Storage Facility

       The ALJs recommend inclusion of the costs of operating the Spindletop Facility as requested
by ETI.


D.     Affiliate Transactions

       ETI agreed to remove the following affiliate transactions from its request, which the ALJs
recommend be approved: (1) Project F3PPCASHCT (Contractual Alternative/Cashpo) in the
amount of $2,553; (2) Project F3PCSPETEI (Entergy-Tulane Energy Institute) in the amount of
$14,288; and (3) Project F5PPKATRPT (Storm Cost Processing & Review) in the amount of $929.
Except as noted below, all remaining affiliate transactions should be approved. The ALJs
recommend that the following affiliate transactions not be included:


       ¾          $356,151 (which figure includes the $112,531 agreed to by ETI) of costs
                  associated with Projects F5PCZUBENQ (Non-Qualified Post
                  Retirement) and F5PPZNQBDU (Non Qual Pension/Benf Dom Utl);

       ¾          $10,279 of costs associated with Project F3PPFXERSP (Evaluated
                  Receipts Settlement);

       ¾          $19,714 of costs associated with Project F3PPEASTIN (Willard Eastin et
                  al); and

       ¾          $171,032 of costs associated with Project F3PPE9981S (Integrated
                  Energy Management for ESI).

E.     Jurisdictional Cost Allocation

       The ALJs recommend the use of 12 Coincident Peak (12CP) to allocate capacity-related
production costs between the retail and wholesale jurisdictions.
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F.     Class Cost Allocation

       1. Renewable Energy Credit Rider

       The Commission should deny ETI’s request to institute a renewable energy credit rider, and
the Test Year expense of $623,303 should be used for setting rates in this case. Finally, the
Renewable Portfolio Standard Calculation Opt-Out Credit Rider should be maintained, with an
adjustment to the credit rates to reflect the Test Year data used to set ETI’s base rates.


       2. Class Cost Allocation

       The parties generally agreed that ETI’s cost-of-service study comported with accepted
industry practices, but some parties had issues with specific items discussed below.


                    (a) Municipal Franchise Fees

       Municipal franchise fees should be allocated on the basis of in-city kilowatt-hour (kWh)
sales, without an adjustment for the municipal franchise fee rate in the municipality in which a given
kWh sale occurred. The ALJs recommend adoption of ETI’s proposal to collect costs from all
customers taking service from the system.


                    (b) Miscellaneous Gross Receipts Tax

       Similar to municipal franchise fees, miscellaneous gross receipts taxes should be allocated to
the rate classes according to ETI’s cost of service study.


                    (c) Capacity-Related Production Costs

       The ALJs recommend the use of Average and Excess 4 Coincident Peak (A&E 4CP) to
allocate capacity-related production costs, as proposed by ETI. The ALJs do not find sufficient
support to allocate the reserve equalization payments differently than other capacity-related
production costs.
SOAH DOCKET NO. XXX-XX-XXXX              PROPOSAL FOR DECISION                                 PAGE 12
PUC DOCKET NO. 39896


                    (d) Transmission Costs

       ETI’s proposed methodology for allocation of transmission costs should be approved. A&E
4CP is a well-accepted method for allocating such costs.


       3. Revenue Allocation

       Revenue allocation in this case should be based on each class’s cost of service and consistent
with the ALJs’ recommendations in the PFD that impact revenue allocation.


       4. Rate Design

                    (a) Lighting and Traffic Signal Schedules

       ETI should be directed to perform a light emitting diode (LED) lighting cost study before
significant changes are made to its lighting rates. The ALJs further recommend that ETI conduct
this study before filing its next rate case and provide the results of any completed study to Cities and
interested parties. The study should include detailed information regarding differences in the cost of
serving LED and non-LED lighting customers, if ETI currently has LED lighting customers taking
service. ETI should modify the applicable tariffs to eliminate its fee for any replacement of a
functioning light with a lower-wattage bulb.


                    (b) Demand Ratchet

       ETI’s proposed Large Industrial Power Service (LIPS) tariff should be amended to include
the language proposed by DOE witness Etheridge.


                    (c) Large Industrial Power Service

        The ALJs recommend the adoption of a $630 customer charge for this customer class, a
slight decrease in the LIPS energy charges, and an increase in the demand charges from current rates
for this class, as proposed by Staff witness Abbott.
SOAH DOCKET NO. XXX-XX-XXXX            PROPOSAL FOR DECISION                          PAGE 13
PUC DOCKET NO. 39896


                   (d) Schedulable Intermittent Pumping Service

       The Commission should adopt the Schedulable Intermittent Pumping Service rider proposed
by DOE witness Etheridge.


                   (e) Standby Maintenance Service

       The Commission should adopt the changes to Schedule SMS recommended by TIEC, with
the exception of a $6,000 customer charge. Consistent with the ALJs’ recommendation that a new
LIPS charge of $630 is reasonable, the Standby Maintenance Service (SMS) charge should be
limited to $630 and not apply if a Schedule SMS customer also purchased supplementary power
under another applicable rate.


                   (f) Additional Facilities Charge

       Schedule AFC should be changed in accordance with TIEC’s recommendations and those
recommended numbers should be reduced in proportion to any authorized reduction in ETI’s
proposed rate of return, O&M expense, and property tax expense.


                   (g) Large General Service

       Schedule LGS should be amended as proposed by Kroger. Schedule LGS also has a demand
ratchet, and the ALJs’ recommendation for the elimination of ETI’s LIPS demand ratchet is
applicable to this class


                   (h) General Service

       The Commission should adopt the decrease in the Schedule GS customer charge to $39.91
from the current (and Company proposed) rate of $41.09, as well as Staff’s recommended decrease
in energy charges. Schedule GS also has a demand ratchet, and the ALJs’ recommendation for the
elimination of ETI’s LIPS demand ratchet is applicable to this class.
SOAH DOCKET NO. XXX-XX-XXXX              PROPOSAL FOR DECISION                                 PAGE 14
PUC DOCKET NO. 39896


                   (i) Residential Service

       ETI’s declining block winter rates provide a disincentive to energy efficiency. The ALJs
recommend an initial 20 percent reduction, followed by 20 percent subsequent reductions of the
differential in the next three rate cases unless ETI provides sufficient evidence that such changes are
unjust and unreasonable.


G.     MISO Transition

       The Commission should deny ETI’s request for deferred accounting of its MISO transition
expenses to be incurred on or after January 1, 2011. However, the Commission should authorize
ETI to include $2.4 million of MISO transition expense in base rates set in the present case, based on
a five-year amortization of $12 million in total projected expenses. Further, the Commission should
authorize ETI to include in base rates $52,800 in MISO transition expenses for the 2010 portion of
the Test Year expenses, plus $2.4 million for the post Test Year adjustment, for a total of
$2,452,800.


       V.     RATE BASE [Germane to Preliminary Order Issue Nos. 4, 10, and 16]

A.     Capital Investment [Germane to Preliminary Order Issue No. 17]

       ETI presented for review $408,078,600 in capital additions closed to plant in service between
July 1, 2009, and June 30, 2011; that is, from the end of the test year in the Company’s last base rate
case, which was Docket No. 37744, through the Test Year presented in this case. The capital
additions were detailed in the testimony and exhibits of the following Company witnesses: Garrison
(Generation), McCulla (Transmission), Corkran (Distribution), Stokes (Customer Service), Brown
(Information Technology), Plauche (Administrative), Cicio (System Planning and Operations),
Hunter (Supply Chain), May (Regulatory), and Sloan (Legal).4 The evidence shows that these


4
  ETI Ex. 27 (Garrison Direct) at 20-28 and WWG-4; ETI Ex. 32 (McCulla Direct) at 64-92 and MFM-16;
ETI Ex. 25 (Corkran Direct) at 78-108 and SBC-3; ETI Ex. 37A (Roman Direct, adopted by Stokes) at 121-
125 and AFR-5; ETI Ex. 24 (Brown Direct) at 29-37 and JFB-3; ETI Ex. 20 (Plauche Direct) at 37-44 and
TCP-11; ETI Ex. 39 (Cicio Direct) at 71-75 and PJC-6; ETI Ex. 16 (Hunter Direct) at 34-38 and JMH-7; ETI
Ex. 7 (May Direct) at 53-54 and PRM-3; and ETI Ex. 38 (Sloan Direct) at 37-43 and RDS-4.
SOAH DOCKET NO. XXX-XX-XXXX              PROPOSAL FOR DECISION                                PAGE 15
PUC DOCKET NO. 39896


capital additions were prudently incurred and are used and useful in providing service to ETI’s
customers. No party challenged any of the capital additions or the costs thereof, and the ALJs find
no reason to do so either.


B.     Hurricane Rita Regulatory Asset

       Hurricane Rita struck the upper Texas coast in September 2005, causing extensive property
damage. In 2006, the Texas Legislature enacted PURA Chapter 39 to authorize electric utilities such
as ETI to securitize the recovery of their reconstruction costs incurred as a result of Hurricane Rita.
Under the statute, the amount of reconstruction costs to be securitized had to be reduced by the
insurance proceeds and government grants received by a utility. If additional insurance or grant
proceeds were received after the securitization order was approved, the Commission was required to
take those amounts into account in the utility’s next base rate case. This was provided in
Section 39.459(c) of PURA:


       To the extent a utility subject to this subchapter receives insurance proceeds,
       governmental grants, or any other source of funding that compensates it for hurricane
       reconstruction costs, those amounts shall be used to reduce the utility’s hurricane
       reconstruction costs recoverable from customers. If the timing of a utility’s receipt
       of those amounts prevents their inclusion as a reduction to the hurricane
       reconstruction costs that are securitized, the commission shall take those amounts
       into account in:

               (1) the utility’s next base rate proceeding; or
               (2) any proceeding in which the commission considers hurricane
                   reconstruction costs.

       Docket No. 32907 was the proceeding for ETI to determine the amount of Hurricane Rita
reconstruction costs that it could securitize, net of any proceeds received from insurance or
government grants.5 In that case, ETI asserted that it incurred $393,236,384 in Hurricane Rita
reconstruction costs for its Texas Retail jurisdiction. The parties reached a settlement in that case,
which set ETI’s hurricane reconstruction expenses eligible for securitization at $381,236,384. In


5
 Application of Entergy Gulf States, Inc. for Determination of Hurricane Reconstruction Costs, Docket
No. 32907 (Dec. 1, 2006).
SOAH DOCKET NO. XXX-XX-XXXX                PROPOSAL FOR DECISION                                   PAGE 16
PUC DOCKET NO. 39896


addition, ETI estimated that it would receive $65,700,000 in future insurance proceeds that, pursuant
to the settlement, was deducted from the amount to be securitized. The parties also agreed that after
ETI received all of its insurance payments, a true-up would occur to reflect the difference between
the $65,700,000 credited and the amount actually received. The settlement agreement provided that
if ETI received more insurance payments than estimated, the excess payments would be passed
through to ratepayers in the form of a rider; however, the agreement did not address how an under-
recovery by ETI would be handled. It turned out that ETI received only $46,013,904 in insurance
proceeds,6 leaving a $19,686,096 under-recovery by ETI, which the parties refer to as Overestimated
Insurance Proceeds.7


          Docket No. 37744 was ETI’s next base rate case after Docket No. 32907. In Docket
No. 37744, ETI requested recovery of the Overestimated Insurance Proceeds by establishing a
regulatory asset of $19,686,096, plus accrued carrying costs, to be amortized over five years.8
Docket No. 37744 also concluded by a black-box settlement, and neither the Stipulation and
Settlement Agreement nor the Order entered by the Commission specifically addressed the proposed
regulatory asset or any other recovery for Overestimated Insurance Proceeds.


          In the present case, ETI has again sought approval of a regulatory asset to recover
$26,229,627, for the balance of Overestimated Insurance Proceeds, plus carrying costs through
June 30, 2011.9 Cities objected to the amount of ETI’s request. They argue that this issue was
resolved in Docket No. 37744 and that ETI should have been amortizing the asset since the
conclusion of that case. Staff also argues that the issue was resolved in Docket No. 37744 and
requested that ETI’s request be denied entirely; or, alternatively, that it should be considered
partially amortized and accordingly reduced. ETI argues that the issue was not resolved in Docket
No. 37744 and that it should be allowed a full recovery in the present case. Alternatively, ETI
argues that Cities’ proposed reduction was not calculated correctly.

6
    See Docket No. 32907, Final Order at FoF 27. Cities Ex. 2 (Garrett Direct) at Exhibit MG2.3.
7
    $19,686,096 = 65,700,000 - $46,013,904.
8
    Cities Ex. 2 (Garrett Direct) at 11.
9
    Schedule P Cost of Service Workpapers, Vol. 2, ETI Ex. 3 at AJ 15, page 15.3.
SOAH DOCKET NO. XXX-XX-XXXX                   PROPOSAL FOR DECISION                          PAGE 17
PUC DOCKET NO. 39896


          Cities’ expert accounting witness, Mark Garrett, testified that ETI should have been
amortizing the balance of Overestimated Insurance Proceeds since the effective date of rates set in
Docket No. 37744. In addition, he argues that ETI should not have continued to accrue interest on
the balance that was added into rate base in that docket, because it would have then earned a rate of
return. Therefore, Mr. Garrett’s adjustment started with the balance of $25,278,210 that ETI
requested in Docket No. 37744. He reduced that balance by $9,479,329 for amortization between
the date rates went into effect in Docket No. 37744 and the date that rates will go into effect in the
current case (22.5 months). Mr. Garrett further reduced the remaining balance by $5,678,960 to
account for additional insurance proceeds received by ETI after Docket No. 37744.                 By
Mr. Garrett’s calculations, this left a remaining balance of Overestimated Insurance Proceeds of
$11,071,338.10 Both Mr. Garrett and Cities witness Jacob Pous also recommended that this
remaining balance not be carried as a regulatory asset but, instead, be moved to the storm insurance
reserve for recovery.11 In their view, this would ensure that the remaining balance would be
properly recovered.


          In response to ETI’s argument that the Hurricane Rita Regulatory Asset was not resolved in
Docket No. 37744, Cities stress that Docket No. 37744 settled as a “black box settlement.” In
Cities’ opinion, such a settlement should not be interpreted as changing the status quo unless
expressly stated in the settlement agreement or final order. Cities contend that the status quo in
Docket No. 37744 was that ETI was authorized to recover its Over Estimated Insurance Proceeds,
because recovery was authorized by PURA § 39.459(c); recovery had been previously approved in
Docket No. 32907; and no party objected to its recovery in Docket No. 37744. Therefore, Cities
state, the final order in Docket No. 37744 should be interpreted as authorizing ETI’s requested
recovery of the Hurricane Rita Regulatory asset in the rates set in that docket.12


          Cities also disagree with ETI’s alternative argument that Mr. Garrett improperly calculated
the remaining balance of the asset by deducting an amount for insurance proceeds ETI received after

10
     Cities Ex. 2 (Garrett Direct) at Exhibit MG2.3.
11
     Id. (Garrett Direct) at 12; Cities Ex. 5 (Pous Direct) at 64.
12
     Cities Reply Brief at 10-14.
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Docket No. 37744 concluded. Cities state that Mr. Garrett’s adjustment was correct because it
began with the balance requested in Docket No. 37744, before the additional insurance proceeds
were received. In other words, Mr. Garret did not start with the balance claimed by ETI in the
present case,13 so he correctly applied the amount received after Docket No. 37744 to reduce the
balance claimed in that docket.14 According to Cities, Mr. Garrett began with the prior balance to
properly reflect that no carrying charges would accrue on the balance after it was included in rate
base and recovered a return through rates.15 Cities also dispute ETI’s argument that Mr. Garrett
should not have accounted for amortization occurring between the Test Year and the Rate Year as an
“invalid post-test year adjustment.”16 In Cities’ view, this was a valid known and measureable
change that should be taken into account.17


           Staff recommends that the Hurricane Rita Regulatory Asset be removed from rate base
entirely. Staff witness Anna Givens stated that it is reasonable to assume that this asset was included
as part of the settlement in Docket No. 37744. Accordingly, she stated that it is not appropriate for
ETI to request recovery of the same asset in the present docket.             Therefore, Ms. Givens
recommended removal of the entire requested $26,229,627 Hurricane Rita regulatory asset from
ETI’s rate base.18


           Alternatively, Ms. Givens proposed that the Commission allow ETI a regulatory asset of
$17,486,418, to be amortized over 40 months. Ms. Givens noted that higher rates from Docket
No. 37744 first went into effect on August 15, 2010;19 therefore, at least one-third of the regulatory
asset should have been amortized by the conclusion of the present case. Using ETI’s updated
hurricane regulatory asset request of $26,229,627, Ms. Givens recommended a decrease of one-third


13
     Cities Initial Brief at 8.
14
     Cities Ex. 2B (Garrett Direct), Exhibit MG-2.3.
15
     Docket No. 32907, Final Order at FoF 28.
16
     ETI’s Initial Brief at 7.
17
     Cities’ Reply Brief at 10-14.
18
     Staff Ex. 1 (Givens Direct) at 32-34.
19
     Docket No. 37744, Order, FoF 16 (Dec. 13, 2010).
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PUC DOCKET NO. 39896


to ETI’s request. This would equal an $8,743,209 reduction, resulting in her recommended
regulatory asset of $17,486,418 ($26,229,627 - $8,743,209). Ms. Givens also recommended that the
amortization period be decreased from 60 months to 40 months, which is the time remaining on
ETI’s original Docket No. 37744 request.20


          ETI disagrees with Cities and Staff, and it argues that its total requested Hurricane Rita
regulatory asset should be included in rate base in this case. First, it notes that no instruction in the
Stipulation and Settlement Agreement filed in Docket No. 37744 required ETI to begin amortizing
the asset or otherwise directed the treatment of the asset. Likewise, no Finding of Fact or
Conclusion of Law in the agreed order entered in Docket No. 37744 authorized the proposed
treatment of the asset. In contrast, ETI notes, the settlement in Docket No. 32907 does specifically
address the treatment of this asset, and it argues that its request to include the full Hurricane Rita
regulatory asset in rate base in the present case is consistent with that settlement. In ETI’s opinion,
it has not previously been authorized to establish the regulatory asset, it has not amortized it, and the
full amount should be included in rate base in this case.21


          Alternatively, if Cities’ proposed amortization is accepted, ETI argues that Mr. Garrett’s
calculations were wrong. First, ETI states, Mr. Garrett incorrectly assumed that the $26,229,627
Hurricane Rita regulatory asset requested in this case did not account for the $5,678,960 of
insurance proceeds that ETI received after Docket No. 37744. According to ETI, the $5,678,960
was accounted for, as shown on WP/P AJ 15.3. Therefore, ETI states, Mr. Garrett’s adjustment for
this $5.6 million would remove this amount from the asset a second time.22 Second, ETI argues that
Mr. Garrett erred by amortizing the asset by 22.5 months. Mr. Garrett calculated the amortization
period from the time rates went into effect after Docket No. 37744 (August 15, 2010) through the
time revised rates would go into effect in this docket (June 30, 2012). ETI states that Mr. Garrett

20
   Staff Ex. 1 (Givens Direct) at 34. Ms. Givens noted that amount recommended in Docket No. 37744 was
$25,278,000, which is $951,627 less than the amount requested in the current proceeding. However, she
stated that this does not affect her recommendation, because by the time the hearing on the merits concluded,
at least another two months of amortization expense under the existing rates would be collected by the ETI
and should adequately compensate it for the difference. Staff Ex. 1 (Givens Direct) at 35.
21
     ETI Ex. 46 (Considine Rebuttal) at 19-24; ETI Initial Brief at 5-6.
22
     ETI Ex. 46 (Considine Rebuttal) at 21-22; ETI Initial Brief at 7.
SOAH DOCKET NO. XXX-XX-XXXX                  PROPOSAL FOR DECISION                           PAGE 20
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made an invalid post-test year adjustment because post-test year adjustments for rate base items are
limited to plant additions recorded in FERC Accounts 101 or 102. In contrast, regulatory assets, like
the Hurricane Rita regulatory asset, are recorded in Account 182.3. Therefore, in ETI’s opinion, if it
was required to amortize this regulatory asset, it would be appropriate to amortize it for only
10.5 months, to the end of the Test Year (August 15, 2010, through June 30, 2011). These two
corrections would adjust Mr. Garrett’s proposed asset balance from $10,714,557 to $21,805,940.23


          ETI also disagrees with Mr. Pous’ recommendation that the regulatory asset be removed
from rate base and placed in the storm reserve, to be amortized over 20 years. In ETI’s opinion, this
approach would defeat the purpose of securitization, which is to provide ETI with cost recovery in
an expedited manner.24


          Finally, ETI argues that Ms. Givens’ analysis was flawed. It reiterated that no provision in
the Stipulation and Settlement Agreement or the final order filed in Docket No. 37744 directed the
treatment of the regulatory asset or stated that ETI would begin amortizing the asset. Further, ETI
stresses that it never sought recovery of the entire asset all at once in Docket No. 37744. Instead,
ETI requests recovery over a period of years through amortization. Thus, according to ETI, even if
Ms. Givens’ argument were accepted, the entire asset should not be disallowed.25


          This issue is a close call because the black-box settlement agreement and final order in
Docket No. 37744 did not expressly state how the Hurricane Rita regulatory asset issue was
resolved. The following factors support finding that the Hurricane Rita regulatory asset issue was
resolved in Docket No. 37744:


x     the settlement agreement and final order in Docket No. 32907 expressly provided that the
      difference between the amount of ETI’s estimated insurance proceeds and the amount actually
      received by ETI would be trued up after ETI received the proceeds;



23
     ETI Ex. 46 (Considine Rebuttal) at 22; ETI Initial Brief at 7-8.
24
     ETI Initial Brief at 8.
25
     ETI Ex. 46 (Considine Rebuttal) at 21; Id. at 8-9.
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PUC DOCKET NO. 39896


x   PURA § 39.459(c) provides that if the timing of a utility’s receipt of insurance proceeds
    prevented their inclusion as a reduction to the securitized costs, the Commission “shall take
    those amounts into account . . . in the utility’s next base rate proceeding;”

x   Docket No. 37744 was ETI’s next base rate proceeding;

x   in Docket No. 37744, ETI requested a true-up concerning the insurance proceeds, and it
    requested that a regulatory asset be established for the deficit and amortized over five years;

x   in Docket No. 37744, no party objected to ETI’s proposed regulatory asset or amortization;

x   the stipulation and settlement agreement entered by the parties in Docket No. 37744 stated that
    the parties resolved all issues, except for ETI’s Competitive Generation Service (CGS) proposal;
    and

x   neither the stipulation and settlement agreement nor the Order entered in Docket No. 37744
    specifically disapproved, excluded, or deferred consideration ETI’s proposed regulatory asset,
    although they did specifically exclude or disapprove other items, such as ETI’s CGS proposal
    and various proposed riders.


       On the other hand, some factors support a finding that the Hurricane Rita regulatory asset
issue was not resolved in Docket No. 37744. The stipulation and settlement agreement and the
Order entered in Docket No. 37744 did not expressly approve ETI’s proposed regulatory asset,
although certain other items were expressly approved, such as River Bend Nuclear Generating
Station Unit No. 1 (River Bend) decommissioning costs, depreciation rates, and other items. Also,
utilities are typically not allowed to create regulatory assets without express approval of the
Commission.


       Thus, the difficulty with this issue is the nature of the black-box settlement of Docket
No. 37744. In the settlement, the parties agreed to an increase in base rate revenues of $59 million
effective August 15, 2010, with an additional increase in base rate revenues effective May 2, 2011.
However, there was no explanation on how this increase was determined, and there was no specific
agreement or finding on the amount of ETI’s rate base or its reasonable and necessary cost of
service. In that case, there was no objection to ETI’s proposed Hurricane Rita regulatory asset, it
was authorized by the prior settlement in Docket No. 32907, and the Commission was directed by
SOAH DOCKET NO. XXX-XX-XXXX               PROPOSAL FOR DECISION                                 PAGE 22
PUC DOCKET NO. 39896


PURA § 39.459(c) to take into account ETI’s insurance proceeds related to the Hurricane Rita
securitized costs in ETI’s next rate case, which was Docket No. 37744. Moreover, when there is
uncertainty whether an undisputed issue was deferred for future consideration or was included
within the rates set in a black-box settlement, the burden should be on the utility to establish that the
issue was deferred for future consideration. When all the evidence and factors are considered, the
ALJs find that that ETI’s proposed Hurricane Rita regulatory asset should be considered as having
been approved in Docket No. 37744, and ETI should have amortized the asset since August 15,
2010, the effective date of rates approved in that docket.


        The ALJs also find that none of the amortization calculations proposed by the parties were
entirely correct. ETI’s proposal to start with its requested $26,229,627 was flawed because it
included carrying costs from August 15, 2010, when the asset should have been included in rate
base, to June 30, 2011, the end of the Test Year in the present case. During that period, the asset
would have earned a rate of return as part of rate base, and accrual of carrying costs should have
ceased. Therefore, it would be more accurate to begin amortizing the Hurricane Rita regulatory
asset by using the balance requested by ETI in Docket No. 37744. That amount, according to Mr.
Garrett, was $25,278,210. However, the amortization calculation should not extend beyond the end
of the Test Year in the present case (June 30, 2011), as proposed by Cities and Staff. P.U.C. SUBST.
R. 25.231(c)(2)(F)(ii) provides for post-test-year reductions to rate base, and the recommendation for
a post-test-year adjustment to the Hurricane Rita regulatory asset does not fall within the scope of
that rule. The balance remaining after amortization to the end of the Test Year should be further
reduced by $5,678,960 to account for additional insurance proceeds received by ETI after Docket
No. 37744 concluded but before the end of the Test Year in the present case. ETI argues that this
reduction was already included in its request. However, as discussed above, the appropriate
calculation should begin with the balance of the asset at the conclusion of Docket No. 37744, not the
balance requested by ETI in the present case. The balance of the asset at the conclusion of Docket
No. 37744 did not account for the additional insurance proceeds paid to ETI afterwards, so it should
be deducted now. In summary, the ALJs find that the appropriate amount of the Hurricane Rita
regulatory asset to be included in rate base in this case should be calculated as follows:
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PUC DOCKET NO. 39896


Beginning balance at conclusion of Docket No. 37744 (original balance + carrying charges)   $25,278,210

Less amortization for period 8/15/10 to 6/30/11 = 10.5 months / 60 months = 17.5%           - $4,423,687

Less additional insurance proceeds received                                                 - $5,678,960

Remaining balance of Hurricane Rita regulatory asset                                        $15,175,563


          Finally, the ALJs recommend that the Commission not adopt the recommendation of Cities
to move the Hurricane Rita regulatory asset to the storm insurance reserve for recovery. As noted by
ETI, one purpose of enactment of PURA Chapter 39 was to allow expedited recovery of costs
resulting from Hurricane Rita storm damage. Moving the regulatory asset to the storm insurance
reserve would defeat that purpose and negate the five-year amortization plan the parties agreed to in
Docket No. 37744.


          In summary, the ALJs find that ETI’s proposed Hurricane Rita regulatory asset was an issue
resolved by the black-box settlement in Docket No. 37744. Therefore, ETI should have included the
asset in rate base at the conclusion of that docket and should have begun amortizing it over a period
of five years. The accrual of carrying charges should have ceased when Docket No. 37744
concluded, because the asset would have then begun earning a rate of return as part of rate base. The
appropriate calculation of the asset should begin with the amount claimed by ETI in Docket
No. 37744, less amortization accruals to the end of the Test Year in the present case, and less the
amount of additional insurance proceeds received by ETI after the conclusion of Docket No. 37744.
This produces a remaining balance of $15,175,563, which should remain in rate base as a regulatory
asset, applying a five-year amortization rate that commenced August 15, 2010. Further, the
Hurricane Rita regulatory asset should not be moved to the storm insurance reserve.


C.        Prepaid Pension Asset Balance

          ETI included in rate base an item titled Unfunded Pension in the amount of $55,973,545.26
The amount requested in this account represents the accumulated difference between the Statement
of Financial Accounting Standards (SFAS) No. 87 calculated pension costs each year and the actual

26
     ETI Ex. 3, Sched. B-1, Line 10.
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PUC DOCKET NO. 39896


contributions made by the Company to the pension fund.27 It is a debit balance, meaning that the
Company has contributed roughly $56 million more to its pension fund than the minimum required
by SFAS 87.28 Other than Cities, no party opposes ETI’s request to include this item in rate base.


          Cities argue that ETI ought not be entitled to include this amount in rate base because it
represents amounts the ETI overpaid to its pension, resulting in little to no benefit to ratepayers.
Cities witness Mark Garrett pointed out that ETI earned only 1.37 percent on its pension assets over
the past five years, while it is seeking a rate of return of more than 11 percent. Thus, he argues, if
the asset were included in rate base, ratepayers would pay a substantial premium for the slight
pension cost savings ETI’s excess contributions may have achieved.29


          Cities argue that the entire prepaid pension asset should be removed from rate base because
ETI has not justified its inclusion. This would reduce pro forma rate base by $36,382,803, which is
the net amount of the prepaid balance less accumulated deferred income tax ($55,973,545 –
$19,590,740 = $36,382,803). At the same time, Cities would increase operating expense by
$498,284, to provide a 1.37 percent return on the net balance of ETI’s prepaid pension asset
balance.30


          Alternatively, Cities contend that the Commission should treat the pension assets in the same
manner as the approach adopted by the Commission in Docket No. 33309.31 In that docket, the
Commission allowed a pension prepayment asset, less accrued deferred federal income taxes
(ADFIT) and less the portion of the asset that is capitalized to CWIP, to be included in rate base. As
to the excluded portion, the Commission allowed the accrual of an allowance for funds used during
construction (AFUDC). Thus, Cities contend, if the Commission opts for this approach, it should
allow ETI’s pension prepayment asset, less ADFIT, to be included in rate base, but excluding

27
     Cities Ex. 2 (Garrett Direct) at 7.
28
     ETI Initial Brief at 10; Cities Ex. 2 (Garrett Direct) at 8.
29
     Cities Ex. 2 (Garrett Direct) at 8-9.
30
     Id. at 10, MG-2.2; Cities Initial Brief at 10.
31
  Remand of Docket No. 33309 (Application of AEP Texas Central Company for Authority to Change Rates),
Docket No. 38772, Order on Remand at FoF 15A (Jan. 30, 2011).
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PUC DOCKET NO. 39896


$25,311,236 for the portion of the prepaid pension balance associated with CWIP, and allow
AFUDC to accrue on the excluded balance.32


           ETI responds first by disputing Mr. Garrett’s contention that it has unreasonably overpaid
into its pension fund. It contends it has made contributions to the pension fund in accordance with
contribution guidelines established by the Employee Retirement Income Security Act of 1974 and
the Internal Revenue Code of 1986, and that the contributions were within the allowable range of
contributions deductible for tax purposes. ETI also was guided in its required pension contributions
by the Pension Protection Act of 2006 rules, effective beginning with the 2008 plan year.33


           ETI next disputes Cities’ contention that the earnings associated with ETI’s pension
contributions provide insufficient benefits to justify inclusion of the asset in rate base. ETI points
out that ratepayer benefits are not just limited to the level provided by the actual pension fund
earnings on investment. Rather, under FAS 87, pension costs included in the cost of service for
ratemaking purposes are intended to include the expected rate of return on assets. Thus, ETI argues
that the expected long-term rate of return on ETI’s assets is 8.5 percent, not the actual earnings as
suggested by Mr. Garrett.34


           On behalf of ETI, Mr. Considine testified that the pension balance is no different than any
other prepayments made by the Company, which are included in rate base and earn a full return on
rate base. Furthermore, the Company would be allowed to earn a full return on rate base had the
Company invested these same dollars in Plant in Service, but the Company in this case used funds to
contribute to a still under-funded pension plan and at the same time provided a timely reduction to
formerly FAS 87 annual pension cost, thereby immediately benefitting ratepayers.35 Therefore, ETI
argues it is clearly investor-supplied capital and accordingly should earn the Company’s requested
return on rate base.


32
     Cities Initial Brief at 8-9; Cities Ex. 2 (Garret Direct) at 12.
33
     ETI Ex. 46 (Considine Rebuttal) at 22.
34
     Id.
35
     Id. at 23-24.
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          ETI acknowledged the approach to this issue taken by the Commission in Docket No. 33309,
but failed to explain why it is distinguishable from the present case.36


          The ALJs conclude that the approach taken by the Commission in Docket No. 33309 was
sound and should be applied in the present case. Neither party adequately explained why the
circumstances of the present case are distinguishable. Thus, the ALJs recommend that the
CWIP-related portion of ETI’s pension asset ($25,311,236 out of the total asset) should be excluded
from the asset, but accrue allowance for funds used during construction.


D.        FIN 48 Tax Adjustment

          The Financial Accounting Standards Board (FASB) is the body that establishes the rules that
constitute generally accepted accounting principles (GAAP). FASB’s Interpretation No. 48
(FIN 48) prescribes the way in which a company must analyze, quantify, and disclose the potential
consequences of tax positions that the company has taken which are legally “uncertain.” Pursuant to
FIN 48, ETI and its independent auditors are required to evaluate each of its uncertain tax positions
to determine, under the most objective, reasonable standards, which portion of each position will
most likely ultimately have to be paid to taxing authorities if challenged by the authorities. FIN 48
requires that this portion be excluded from ADFIT for financial reporting purposes and accrue
interest and, in some cases, penalties.37


          ETI and its auditors periodically perform the FIN 48 analysis. In so doing, they have
concluded that the Company has taken a number of uncertain tax positions that the Company expects
to lose if challenged by the IRS. ETI concluded that these uncertain tax positions result in a total of
$5,916,461 in tax dollars that the Company expects it will ultimately have to pay, with interest, to
the IRS. As required by FIN 48, this amount is recorded on ETI’s balance sheet as a tax liability.38
In other words, ETI has, thus far, avoided paying to the IRS $5,916,461 in tax dollars (ETI’s FIN 48


36
     ETI Initial Brief at 10-11.
37
     ETI Ex. 70 (Warren Rebuttal) at 9-12.
38
     ETI Ex. 64 (Roberts Rebuttal) at 4-7.
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PUC DOCKET NO. 39896


Liability) in reliance upon tax positions that the Company believes will not prevail in the event the
positions are challenged, via an audit, by the IRS.


           In preparing its application in this proceeding, ETI made an accounting adjustment to its Test
Year numbers by not including the $5,916,461 in its ADFIT balance. This had the effect of reducing
the Company’s Test Year deferred tax balance and, therefore, increasing its rate base.39


           Cities witness Mark Garrrett asserted that the deduction of $5,916,461 – representing ETI’s
FIN 48 Liability – should be added to ETI’s ADFIT balance and thus be used to reduce the
Company’s rate base. Mr. Garrett pointed out that the Commission first considered this issue in a
recent Oncor docket.40 In that docket, the Commission decided to include FIN 48 liabilities in
ADFIT because of the low likelihood that the IRS would actually audit and review the issue.41
Mr. Garrett testified that this is a fair result because: (1) a utility with FIN 48 liabilities might never
have its underlying uncertain tax positions audited by the IRS; and (2) even if the uncertain positions
are audited by the IRS, the utility might prevail on them. In either case, the utility would never have
to pay those tax amounts. Moreover, during the time when the uncertainty exists, the utility enjoys
the use of cost-free capital (from the deferred taxes associated with the deductions) at its disposal.42
Thus, Mr. Garrett recommends that ETI’s ADFIT balance be increased by $5,916,461 to reinstate
the FIN 48 Liability removed by the Company.43


           ETI witnesses Rory Roberts and James Warren stated that the $5,916,461 should not be
included in the Company’s ADFIT balance. Mr. Roberts explained that, because the Company
expects to lose on its uncertain tax positions, it expects that it will ultimately have to pay $5,916,461
in taxes to the IRS, plus interest. Accordingly, Mr. Garrett testified that the amount does not


39
     Id. at 4.
40
  Cities Ex. 2 (Garrett Direct) at 5-7. See also Application of Oncor Electric Delivery Company LLC for
Authority to Change Rates, Docket No. 35717, Order on Reh’g (Nov. 30, 2009).
41
  Id. at 18 FOF 59 (“The IRS may not audit or reverse Oncor’s position as to the tax deductions identified as
FIN 48 deductions and moved into the FIN 48 reserve.”).
42
     Cities Ex. 2 (Garrett Direct) at 5-6.
43
     Id. at 7.
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PUC DOCKET NO. 39896


represent cost-free funds available to the Company and, as such, should not be included in the
Company’s ADFIT balance.44


          Both the Cities and ETI agree that ETI’s rate base “should reflect the actual amount of cost
free capital in the ADFIT accounts at Test Year end.”45 However, ETI witness Mr. Warren testified
that the FIN 48 Liability is not cost-free capital to the Company because the best available expert
opinion in the record of this case is that ETI will “most likely” ultimately have to pay the money to
the IRS, with interest.46


          Moreover, Mr. Warren pointed out that, beginning with 2010 tax returns, a corporate
taxpayer is required to complete and file a Schedule UTP, on which the taxpayer must specifically
identify and describe its FIN 48 positions. Mr. Warren contended that, because ETI must now
annually file a Schedule UTP, it is more likely that the IRS will audit the Company, thereby forcing
it to pay the FIN 48 Liabilities, with interest.47 This constitutes additional support for the notion that
the FIN 48 Liability is not cost-free capital for the Company. Mr. Warren correctly points out that,
in a recent CenterPoint Energy Houston Electric, LLC, (CenterPoint) rate case, the Commission
specifically acknowledged that filing of a Schedule UTP makes it more likely that a company will be
audited. In that case, the ALJs recommended that CenterPoint’s FIN 48 Liability, totaling some
$164 million, be added to CenterPoint’s ADFIT, thereby reducing its rate base. The Commission
adopted the recommendation. However, in light of its conclusion that the filing of a Schedule UTP
increases the likelihood of an audit, the Commission authorized CenterPoint to establish a deferred
tax account rider to enable it to recover any portion of its FIN 48 Liability that it might ultimately be
forced to pay to the IRS, plus interest.48 ETI does not necessarily oppose the use of a rider in this




44
     ETI Ex. 64 (Roberts Rebuttal) at 7.
45
     Cities Ex. 2 (Garrett Direct) at 6; see also ETI Ex. 70 (Warren Rebuttal) at 6-7.
46
     ETI Ex. 70 (Warren Rebuttal) at 17.
47
     Id. at 14, 20-21.
48
  ETI Ex. 70 (Warren Rebuttal) at 19-20. See also Application of CenterPoint Electric Delivery Company,
LLC, for Authority to Change Rates, Docket No. 38339, Order on Reh’g at 3-4 (June 23, 2011).
SOAH DOCKET NO. XXX-XX-XXXX                     PROPOSAL FOR DECISION                                PAGE 29
PUC DOCKET NO. 39896


case, but contends that it would be preferable to simply exclude ETI’s FIN 48 Liability from its
ADFIT balance, thereby increasing its rate base.49


          In the alternative that the Commission rejects ETI’s request to exclude the full amount of the
FIN 48 Liability from the Company’s ADFIT balance, ETI contends that at least any amount of cash
deposit the Company has made with the IRS that is attributable to the FIN 48 Liability should be
removed from the Company’s ADFIT balance.50 The Cities’ witness, Mr. Garrett, agrees.51 Staff
also agrees, arguing that ETI should be required to increase its ADFIT balance by the amount of its
FIN 48 Liability less the amount of any cash deposit attributable to the liability that ETI has made
with the IRS.52 ETI has made a cash deposit with the IRS in the amount of $1,294,683. This
amount is associated with the Company’s FIN 48 Liability.53


          Consistent with prior Commission precedent from the Oncor and CenterPoint proceedings,
the ALJs conclude that ETI’s FIN 48 Liability should be included in the Company’s ADFIT balance.
There is, however, one caveat to this conclusion. The amount of the cash deposit made by ETI to
the IRS which is attributable to the Company’s FIN 48 Liability should not be included in the
ADFIT balance. Therefore, the ALJs recommend that the Commission find that $4,621,778
(representing ETI’s full FIN 48 Liability of $5,916,461 less the $1,294,683 cash deposit ETI has
made with the IRS) should be added to ETI’s ADFIT and thus be used to reduce ETI’s rate base. No
party expressly advocated the addition of a deferred tax account rider,54 and the ALJs do not
recommend one in this case.




49
     ETI Initial Brief at 13; ETI Ex. 70 (Warren Rebuttal) at 20.
50
     ETI Ex. 64 (Roberts Rebuttal) at 8-9.
51
     Cities Ex. 2 (Garrett Direct) at 7 n. 4.
52
     Staff’s Initial Brief at 11-12.
53
     ETI Ex. 64 (Roberts Rebuttal) at 8.
54
   Cities and Staff both point out that there is much less need for a deferred tax account rider in the present
case than there was in the CenterPoint case, where CenterPoint had $164 million in FIN 48 liabilities. Cities
Reply Brief at 18; Staff Reply Brief at 10.
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E.        Cash Working Capital

          Rate base includes a reasonable allowance for cash working capital. Cash working capital
represents the average amount of investor capital used to bridge the gap in time between when
expenditures are made by ETI to provide services and when the corresponding revenues are received
by ETI.55 Generally, an increase in revenue lag days and/or a decrease in expense lead days will
result in an increase to the amount of cash working capital included in the rate base. Conversely, a
decrease in revenue lag days and/or an increase in expense lead days will reduce the cash working
capital included in rate base. A properly prepared lead-lag study can result in either a positive cash
working capital amount (and therefore an increase to the rate base) or a negative cash working
capital amount (and a corresponding decrease to the rate base).


          Pursuant to P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV), ETI calculated its cash working
capital allowance by performing a lead-lag study. ETI witness Jay Joyce prepared the lead-lag study
for the Company. Based upon the study, ETI requests a cash working capital addition to its rate base
of negative $2,013,921.56


          Only Staff and Cities submitted evidence and argument relevant to the cash working capital
requirement. Staff does not challenge the accuracy of the lead and lag days determined in
Mr. Joyce’s study. Instead, Staff witness Anna Givens recommends that the cash working capital
calculation be updated to reflect the impacts of Staff’s recommended adjustments to ETI’s O&M
costs and taxes.57 ETI agrees that the final cash working capital amount should be updated to reflect
the actual revenue requirements approved by the Commission in this case.58


          Cities witness Jacob Pous asserts that Mr. Joyce’s lead-lag study contains a number of errors
which understate the negative cash working capital requirements of the Company. Mr. Pous asserts
that the correct cash working capital amount for inclusion in ETI’s rate base is negative $24,000,000

55
     ETI Ex. 17 (Joyce Direct) at 4.
56
     Id. at 20 and JJJ-3.
57
     Staff Ex. 1 (Givens Direct) at 30-31.
58
     ETI Ex. 54 (Joyce Rebuttal) at 37; ETI Initial Brief at 14.
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(more than an order of magnitude increase of the negative amount).59 Each of the major components
of the lead-lag study, and Cities’ criticisms of same, will be discussed in turn.


           1. The Revenue Lag Component of the Lead-Lag Study

           Mr. Pous raises a number of criticisms about the revenue lag component of Mr. Joyce’s lead
lag study. There are four parts to the revenue lag component: (1) the “service period lag,” which
consists of the roughly 15 days from the mid-point of the month in which service is provided to the
end of that month; (2) the “billing lag,” which represents the time between the date a customer’s
meter is read and the date a bill is issued to the customer; (3) the “collection lag,” which represents
the time between the issuance of the bill and the date the customer’s payment is received; and
(4) ”receipt of funds lag,” which measures the delay between ETI’s receipt of payment and the
bank’s clearance of the payment.60 When the four parts were combined together, Mr. Joyce
identified ETI’s revenue lag as 43.86 days.61


                       (a) Billing Lag

           Mr. Joyce identified the billing lags (i.e., the delay between when meters are read and bills
are sent to customers) as ranging from 5.4 to 5.65 days, depending upon the customer class.62 On
behalf of the Cities, Mr. Pous asserted that this duration is too long. Mr. Pous complained that the
billing lag in ETI’s lead-lag study is longer than in studies from previous ratemaking proceedings
involving ETI’s predecessor, despite the fact that, in the interim between studies, ETI has invested
substantially in electronic meter reading devices and computer systems that ought to shorten the lag
time. According to Mr. Pous, in a previous proceeding, ETI’s predecessor identified its billing lag
as only 3.61 days.63 Mr. Pous also pointed out that the Railroad Commission of Texas (RRC),
recently adopted a 1-day billing lag for a large gas utility, Atmos Mid-Tex, due to the utility’s use of


59
     Cities Ex. 5 (Pous Direct) at 72.
60
     ETI Ex. 17 (Joyce Direct) at 8-10.
61
     Id. at JJJ-3.
62
     Cities Ex. 5 (Pous Direct) at 74.
63
     Id.
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modern electronic meter reading devices (the Atmos Mid-Tex RRC proceeding). Mr. Pous stated
that the billing lag identified by ETI would unjustly reward the Company for being inefficient in
sending out its bills because customers should not be punished if the utility decides to manage its
billing processing and payment system less efficiently. Thus, Mr. Pous recommended a schedule of
different billing lags for different customer classes. For residential and commercial customers,
Mr. Pous recommended a 1.46 day billing lag, based since ETI’s predecessor claimed such a lag in a
prior PUC docket (Docket No. 12852). For large industrial, public authority, and street lighting
customers, Mr. Pous recommends a billing lag of 3.72 days. He calculated that the combined impact
of these adjustments would result in a 41.10-day total revenue lag (as compared to Mr. Joyce’s
figure of 43.86 days). Mr. Pous then calculates that this shorter lag period results in an additional
negative cash working capital of $11.4 million.64


          ETI responds by pointing out that the 1.46-day billing lag suggested by Mr. Pous for
residential and commercial customers was derived from a rate case by ETI’s predecessor from 1993,
whereas Mr. Joyce more properly relied on actual Test Year data. Mr. Joyce asserted that Mr. Pous,
in effect, “cherry picked” the 1.46-day figure from one page of a 47-page study associated with the
1993 rate case, and that the remaining pages of the study have not been located and, therefore,
cannot be evaluated. Thus, Mr. Joyce testified, “[i]t is unfair and unreasonable to use such an old
document to attempt to support a position when reasonable, contemporaneous evidence exists.”65


          ETI argues that it is more appropriate in this case to rely upon ETI’s actual residential and
commercial billing practices, rather than to substitute artificial and arbitrary 1.46-day and 3.72-day
periods derived from other sources. According to Mr. Joyce, it is unavoidably necessary, when
conducting a lead-lag study, to take into account the actual amount of time employed by ETI in
performing all of the activities in its billing-cycle-based meter reading and billing processes.
Mr. Joyce complains that Mr. Pous’ approach would jettison this actual data and analysis derived




64
     Id. at 75-77.
65
     ETI Ex. 54 (Joyce Rebuttal) at 11.
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from the Test Year and improperly substitute arbitrary numbers based upon a prior, dated, rate
proceeding.66


           Mr. Joyce acknowledged that the RRC recently adopted a 1-day billing lag in the Atmos
Mid-Tex RRC proceeding. He pointed out, however, that the RRC did so simply because Atmos
Mid-Tex failed to present evidence supporting a longer billing lag. Additionally, Mr. Joyce pointed
out that the RRC promptly reversed itself in Atmos Mid-Tex’s next rate case, adopting a longer
billing lag after the company provided sufficient evidence to support the longer period.67


           ETI also provided extensive evidence regarding the details of its meter reading and billing
process.68 ETI witness Dolores Stokes explained that the meter reading and billing cycle includes
time for extensive quality assurance activities to ensure accurate billing, thereby preventing
unnecessary frustration for the customer and additional costs to the Company that would be required
for customer service, rebilling, and account corrections.69


           Cities questioned Mr. Joyce at the hearing about the billing lag period in this case compared
to ETI’s last rate case. Mr. Joyce explained that the total period from meter reading to collection of
billing revenues had not changed appreciably between the two cases, but due to a difference in lead-
lag methodology, the date that divides the two components of that lag – metering to billing and
billing to collection – had changed.70 As a result, the first period – billing lag – was longer than in
the previous case but the second period – collection lag – was shorter.71 ETI introduced into
evidence a response to a Cities RFI that discussed this difference in more detail.72 After explaining




66
     Id. at 5-7.
67
     Id.at 8-9.
68
     ETI Ex. 54 (Joyce Rebuttal); ETI Ex. 66 (Stokes Rebuttal).
69
     ETI Ex. 66 (Stokes Rebuttal) at 18.
70
     Tr. at 499-500, 502.
71
     Tr. at 499-502.
72
     ETI Ex. 73.
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the change in lead-lag methodology, the RFI response concluded that “the combined billing and
collection lags are substantially similar from the prior case to this current case.”73


          The ALJs conclude that ETI has met its burden to show that the billing lag it utilized in the
lead-lag study is reasonable and appropriate. Absent his own opinion, Mr. Pous does not offer
meaningful evidence to support his assertion that the Company’s billing lag is too long or that the
Company’s billing practices are inefficient. For example, he offered no criticism of any specific
billing practice of the Company. The only support for his charge of inefficiency is that the billing
lag in a previous ETI rate case was shorter. Mr. Joyce convincingly explained that this was merely
an artifact of changes in the methodology of the lead-lag study – the billing lag became longer, but
the collection lag became shorter.


          Mr. Pous’ reliance upon an example from the RRC is unconvincing. Similarly, his reliance
upon data from a previous rate case is unpersuasive, especially because only a very limited snippet
of data from that case is available, the case occurred roughly 20 years ago, and it involved a different
company. It is not possible, from the evidence in the record, to know how different or similar ETI’s
current billing practices are to those used in the previous case.


          In this case, ETI has thoroughly explained its metering and billing processes and established
that those processes are reasonable. The Company is therefore entitled to establish rates based on
the actual cash working capital necessary to facilitate those policies. The ALJs recommend rejecting
Cities’ request to shorten the billing lag time identified in ETI’s lead-lag study


                        (b) Collection Lag

          In his lead-lag study, Mr. Joyce identified various collection lags (i.e., the delay between the
issuance of an electric bill and the date the customer’s payment is received) for different classes of
customers. As to third-party customers, the collection lag was determined using a random sample of
invoices from residential, commercial, industrial, public authority, and street light customer billings
during the Test Year, measuring the time between when the bills were mailed and the payment

73
     ETI Ex. 73 at 2.
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PUC DOCKET NO. 39896


receipt date. The collection lag for MSS-4 and Intra-System Bill (ISB) revenues was based on the
actual payment dates for each of the affiliate revenue types.74


               ¾ Collection Lag for Residential Customers

          As to the residential class, Mr. Joyce determined that the collection lag was 23.73 days. On
behalf of the Cities, Mr. Pous disputed the accuracy of that estimate, complaining that it is
substantially longer than the lag identified for commercial customers. Mr. Pous contended that
Mr. Joyce determined the collection lag for residential customers by relying on a sample size that
was too small. Mr. Pous examined the month-end accounts receivable data for ETI’s entire
residential class for the entire Test Year, and concluded that the collection lag for the class is
actually 22.07 days (as compared to Mr. Joyce’s figure of 23.73 days). Mr. Pous then calculated that
this shorter lag period results in an additional negative cash working capital of $2.4 million.75


          Mr. Joyce made several points in response. First, he noted that, although Mr. Pous is
advocating reliance upon month-end accounts receivable data to calculate the collection lag in this
case, he has testified in another proceeding that such data is unusable and unreliable. For example,
in the Atmos Mid-Tex RRC proceeding, Mr. Pous argued in favor of measuring actual bill payment
practices of actual customers (i.e., the approach taken by Mr. Joyce in the present case) and against
analyzing the monthly accounts receivable balances for each month of the Test Year (i.e., the
approach now being advocated for by Mr. Pous).76 Next, Mr. Joyce disputed Mr. Pous’ assertion
that the sample size used by Mr. Joyce was too limited. According to Mr. Joyce, his sample of 100
residential customers is comparable to all of the residential collection lag calculations he has
performed during his 15 years of performing lead-lag studies.77 Mr. Joyce also accused Mr. Pous of




74
     ETI Ex. 17 (Joyce Direct) at 10.
75
     Cities Ex. 5 (Pous Direct) at 77-79.
76
     ETI Ex. 54 (Joyce Rebuttal) at 13-15.
77
     Id. at 15-17.
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inexplicably picking out a few data points, rather than relying upon the entirety of the sampling data,
in order to derive his collection lag estimate.78


           The ALJs are unpersuaded by Mr. Pous’ criticisms and conclude that ETI has met its burden
to show that the collection lag it utilized in the lead-lag study for residential customers is reasonable
and appropriate.


                  ¾ Collection Lag for MSS-4 and ISB Affiliate Rate Classes

           As to MSS-4 and ISB rate classes, Mr. Joyce determined that the collection lags were 46.19
and 15.61 days, respectively.79 Mr. Pous again disputed the accuracy of these estimates. Mr. Pous
pointed out that the underlying data reveals that the majority of the MSS-4 revenue lag days range
from 43 to 46 days, with only two values equaling or exceeding 50 days. Mr. Pous testified that the
two values equaling or exceeding 50 days should be deemed unrepresentative and, therefore,
excluded from the calculations for determining the average lag. Similarly, the majority of ISB
revenue lag days range from 15 to 16 days, with only a few lags running as long as 22 days. Again,
Mr. Pous contended that the longer revenue lag days should be deemed unrepresentative and
excluded from the calculations for the average. Mr. Pous also complained that the payment
deadlines for these affiliate transactions are stipulated in the Entergy System Agreement. Thus, it is
Mr. Pous’ opinion that ETI unreasonably contractually agreed to “excessively long” revenue lag
days associated with the MSS-4 and ISB rate classes. Mr. Pous concluded that if what he considers
to be the unrepresentative lag days are excluded from the calculations, then the collection lag would
change for the MSS-4 class from 46.19 days to 45.14 days, and for the ISB class from 15.61 days to
14.77 days. Collectively, the lag for the two classes would be .77 days shorter, resulting in an
additional negative cash working capital of $3.2 million.80


           Mr. Joyce first responded by disputing Mr. Pous’ contention that there are unusual outliers in
the MSS-4 and ISB payment data. He noted that the lag days for MSS-4 payments ranged from 43

78
     Id. at 17.
79
     Id. at 18.
80
     Cities Ex. 5 (Pous Direct) at 79-81; ETI Ex. 54 (Joyce Rebuttal) at 18.
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to 54 days. He described this as a “relatively tight payment range and certainly within the expected
range of reasonableness.”81 Next, Mr. Joyce described Mr. Pous’ assertion that outlier numbers
should not be considered in the data as nonsensical. Mr. Joyce agreed that, in cases where sampling
is used (such as was done for the residential customer class), it is appropriate to exclude data points
that are unrepresentative of the population as a whole. In the case of the MSS-4 and ISB classes,
however, Mr. Joyce determined the collection lag by reviewing the entire class populations.
According to Mr. Joyce, it is inappropriate to eliminate data points when reviewing an entire
population, unless it is necessary to make a known and measurable change.82


           The ALJs are again unpersuaded by Mr. Pous’ criticisms. The ALJs conclude that ETI has
met its burden as to show that the collection lag it utilized in the lead-lag study is reasonable and
appropriate.


                       (c) Receipt of Funds Lag

           In the lead-lag study, Mr. Joyce identified the receipt of funds lag (i.e., the delay between the
date the funds are received from the customers and the date the funds clear the bank and are
available to ETI).       As required by P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV)(-d-), Mr. Joyce
assumed that one business day is needed to clear any payments by methods other than electronic
transfer, while electronic payments are available to ETI on the date received. Because 53.39 percent
of customer payments were made by methods other than electronic transfer, Mr. Joyce calculated the
receipt of funds lag to be .77 days.83


           Mr. Pous again contended that this duration is too long.         He acknowledges that P.U.C.
SUBST. R. 25.231(c)(2)(B)(iii)(IV)(-d-) mandates the assumption that funds paid by check will be
available “no later than” the following business day. However, he stated that this is merely the
maximum possible duration, and ETI should take into account that fact that many checks are cleared

81
     ETI Ex. 54 (Joyce Rebuttal) at 19.
82
     Id. at 19.
83
   ETI Ex. 17 (Joyce Direct) at 10. The receipt of funds lag is also sometimes referred to by the witnesses as
the “cash receipts float.”
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(and therefore the funds are available) sooner than one day later. Therefore, the funds from all
checks received on any day other than Saturday should be assumed to be available on the date of
receipt, while the funds from checks received on Saturday should be assumed to be available two
days later. Mr. Pous was also critical of the fact that Mr. Joyce treated the funds from all “walk-in”
payments made by customers to be available the next day. Funds from walk-in payments ought to
be deemed available on the date they are received. If these two changes are adopted, Mr. Pous
contended that receipt of funds lag would be shortened from .77 days to .15 days, resulting in an
additional negative cash working capital of $2.1 million.84


          Mr. Joyce first responded by pointing out that Mr. Pous’ contention that all funds are
immediately available except for checks received on Saturdays is simply not accurate. Mr. Joyce
cited from a 2007 Report to Congress made by the Board of Governors of the Federal Reserve
System which supports the conclusion that most funds paid by check in this country are not available
on the day they are received (and a significant portion are still not available the next business day).85
Mr. Joyce also disagreed with Mr. Pous’ contention that all walk-in payments should be considered
immediately available. According to Mr. Joyce, walk-in payments are made at third-party vendor
locations, such as grocery stores and check-cashing stores. Based upon his own investigation,
Mr. Joyce determined that walk-in payments are actually available to ETI two days after receipt.
Thus, his one-day assumption for walk-in payments is conservative.86


          The ALJs conclude that ETI has met its burden as to show that the receipt of funds lag it
utilized in the lead-lag study is reasonable and appropriate. The positions taken by Mr. Pous on this
issue     were     unreasonable      and     counter    to   the    requirements   of   P.U.C.    SUBST.
R. 25.231(c)(2)(B)(iii)(IV)(-d-).




84
     Cities Ex. 5 (Pous Direct) at 81-82; Cities Ex. 5A (Errata No. 1).
85
     ETI Ex. 54 (Joyce Rebuttal) at 21-23.
86
     ETI Ex. 54 (Joyce Rebuttal) at 23-24.
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          2. The Expense Lead Component of the Lead-Lag Study

          For the expense lead portion of his lead-lag study, Mr. Joyce calculated different expense
lead days for numerous different categories of expenses. Each category will be discussed in turn.


                       (a) Expense Lead – Operations and Maintenance Expense

          Mr. Joyce separated O&M expenses into two groups – energy costs and “other O&M”
expenses. Each of those two groups was further divided into subgroups.87


               ¾ Energy Costs

          Fuel. Mr. Joyce explains that, during the Test Year, ETI purchased two kinds of fuel: (1)
coal and oil; and (2) natural gas. He concluded that there were 44.27 expense lead days for coal and
oil, based upon the time between the service periods and payment dates or payment due dates for all
coal and oil invoices from the Test Year. As to natural gas, he determined that there were 40.63
expense lead days, based upon a comparison of the service period and payment due dates and the
payment dates from a random sample of gas invoices.88 No party challenged this approach, and the
ALJs find no reason to do so either.


          Purchased Power. Mr. Joyce explained that there were two components to ETI’s purchased
power energy costs in the Test Year: (1) MSS-4 Purchases; and (2) Other Purchased Power
(consisting of Joint Account Purchases, MSS-3 Purchases, Reserve Equalization, Cogeneration
Purchases, Renewable Energy Credits, and Toledo Bend Purchases). Relying upon either the entire
population or a sample from the Test Year (depending upon the category), Mr. Joyce concluded that
there were 58.76 expense lead days for MSS-4, and 35.79 expense lead days for Other Purchased
Power.89




87
     ETI Ex. 17 (Joyce Direct) at 11.
88
     Id. at 11 and JJJ-3.
89
     ETI Ex. 17 (Joyce Direct) at 12 and JJJ-3.
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          No party challenged the 35.79 day estimate for Other Purchased Power. However, on behalf
of the Cities, Mr. Pous testified that the expense lead days for MSS-4 should be lengthened from
58.76 days to 60.65 days. According to Mr. Pous, Mr. Joyce made several errors in calculating the
expense lead days for MSS-4 expenses. First, Mr. Joyce inadvertently placed the service period
month after the billing month for two MSS-4 invoices. Mr. Pous based this conclusion on the fact
that the expense leads for these two invoices are roughly 30 days shorter than the “vast majority” of
the other invoices.90 In response, Mr. Joyce denied that he erroneously placed the service period
month after the billing month, and pointed out that Mr. Pous lacks any evidence to support his
assertion. Instead, Mr. Joyce considered the entire population of MSS-4 invoices for the Test Year.
Those invoices show payment lead days ranging from 30 to 120 days, with most points being near
30, 60, or 70 payment lead days. According to Mr. Joyce, this is reasonable and well within the
range he has experienced in other rate cases.91


          Mr. Pous testified that Mr. Joyce erred in calculating the expense lead days for MSS-4
expenses by considering only the payment due dates specified in the Entergy System Agreement,
rather than also considering the actual payment dates. According to Mr. Pous, in four instances
during the Test Year, extensions were granted to ETI to allow it to make MSS-4 payments after the
deadline specified in the Entergy System Agreement. Therefore, Mr. Pous stated that the expense
lead days for MSS-4 payments should have been calculated using the later of the actual payment
date or the allowable payment period.92 Mr. Joyce largely agreed with Mr. Pous on this point. That
is, he agreed that the payment lead days should be based on the later of the paid date or the due date.
However, he disagreed with some of Mr. Pous’ calculations on this issue because Mr. Pous wrongly
designated several due dates of Saturday or Sunday, when he should have selected Fridays as the due
date.93




90
     Cities Ex. 5 (Pous Direct) at 83-84.
91
     ETI Ex. 54 (Joyce Rebuttal) at 26-28.
92
     Cities Ex. 5 (Pous Direct) at 84.
93
     ETI Ex. 54 (Joyce Rebuttal) at 28-29.
SOAH DOCKET NO. XXX-XX-XXXX                    PROPOSAL FOR DECISION                         PAGE 41
PUC DOCKET NO. 39896


          Next, Mr. Pous testified that Mr. Joyce erred in calculating the expense lead days for MSS-4
expenses by erroneously concluding that one invoice had been paid on the first of the month when,
in fact, it had been paid on the 18th of the month.94 Mr. Joyce agreed with the change.95 Mr. Joyce
then recalculated the expense lead days for MSS-4 and revised the number of lead days from 58.76
to 59.81.96


          The ALJs conclude that ETI has met its burden as to show that there were 59.81 expense lead
days for MSS-4, and 35.79 expense lead days for Other Purchased Power.


              ¾ Other O&M Expenses

          This category of expenses was broken down in the lead-lag study into four groups – regular
payroll costs, incentive payroll costs, affiliate service company costs, and all other O&M costs (such
as materials, services, and so on).


          Regular Payroll Costs. The lead days for regular payroll costs were computed by
determining the average days of service being reimbursed and adding the days between the end of
each service period and the payments to employees. This amount was then adjusted to incorporate
the effects of vacation pay based upon actual ETI data. By this method, Mr. Joyce determined the
expense lead for regular payroll costs to be 20.68 days.97 No party challenged this approach, and
the ALJs agree.


          Incentive Pay Costs. ETI has an annual employee incentive program in place. Incentive
payments for the year 2010 were made in the first quarter of 2011. The lead days for incentive pay
costs were based on the weighted days between the midpoint of the service period (i.e., July 1, 2010)
and the date the incentives were paid (March 10, 2011). By this method, Mr. Joyce determined the



94
     Cities Ex. 5 (Pous Direct) at 84.
95
     ETI Ex. 54 (Joyce Rebuttal) at 29.
96
     ETI Ex. 54 (Joyce Rebuttal) at JJJ-R-2.
97
     ETI Ex. 17 (Joyce Direct) at 13 and JJJ-3.
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expense lead for incentive pay costs to be 251.77 days.98 No party challenged this approach, and
the ALJs agree.


           Affiliate Service Company Costs and Other O&M Costs. Charges from Entergy Services,
Inc. (ESI) are paid in the month following the month in which the charges were incurred. The lead
days for affiliate service company costs were based on the number of days from the mid-month to
the later of the contractual due date or the actual settlement date in the following month. By this
method, Mr. Joyce determined the expense lead for affiliate service company costs to be 39.64
days.99


           The lead days for other O&M costs were based on a random sampling from the Test Year.
Mr. Joyce originally determined the expense lead for other O&M costs to be 47.46 days.100
However, to correct an error on his part, Mr. Joyce subsequently revised the expense lead time for
other O&M costs down to 43.89 days.101


           Mr. Pous testified that ETI’s “FAS 106-related expenses” were wrongly included in either
the affiliate service company costs or the other O&M costs. FASB is the body that establishes the
rules that constitute GAAP. FASB’s Statement Number 106 (FAS 106) establishes the standards for
an employer’s treatment of the non-cash retirement benefits it gives its employees. Based on the
action taken by the Commission in Docket No. 16705,102 Mr. Pous believes that ETI’s FAS 106
costs should have been separately identified and accounted for in the lead-lag study. He contended




98
      Id. at 14 and JJJ-3.
99
      ETI Ex. 17 (Joyce Direct) at 15, and JJJ-3.
100
      Id. at 15-17, and JJJ-3.
101
      ETI Ex. 54 (Joyce Rebuttal) at JJJ-R-2.
102
   Application of Entergy Gulf States, Inc. for Approval of Its Transition to Competition Plan and the Tariffs
Implementing the Plan, and for the Authority to Reconcile Fuel Costs, to Set Revised Fuel Factors, and to
Recover a Surcharge for Underrecovered Fuel Costs, Docket No. 16705, (Oct. 13, 1998).
SOAH DOCKET NO. XXX-XX-XXXX                   PROPOSAL FOR DECISION                           PAGE 43
PUC DOCKET NO. 39896


that, when those costs are properly accounted for, it results in an additional negative cash working
capital of $3.8 million.103


           Mr. Joyce contended that the prior Commission decision upon which Mr. Pous relies, Docket
No. 16705, dates from 1996, is inapplicable to the facts in the present case, is outdated, and has been
superseded by subsequent Commission decisions. Mr. Pous advocated a 312.55-day expense lead
for FAS 106 expenses. However, Mr. Joyce pointed out that, during the Test Year, ETI made its
FAS 106 payments to a trust at the end of each month, resulting in a one-half month payment lead
(15.25 days). Mr. Joyce testified that his treatment of FAS 106 expenses in his lead-lag study is
consistent with the approach that was approved by the Commission in a recent Oncor ratemaking
case, Docket No. 35717.104


           The ALJs conclude that ETI met its burden to show that there were 39.64 expense lead days
for Affiliate Service Company Costs and 43.89 expense lead days for Other O&M Costs.


                       (b) Expense Lead – Current Federal Income Tax Expense

           As required by P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV)(-f-), Mr. Joyce calculated the lead
days for federal income taxes by measuring the days between the midpoints of the annual calendar
year service periods and the actual dates on which ETI made its estimated quarterly tax payments.
By this method, Mr. Joyce determined the expense lead for current federal income tax costs to be
38 days. He then determined that this resulted in a $1.6 million cash working capital requirement
associated with the Company’s Federal Income Tax Expenses.105


           Mr. Pous testified that the Company’s cash working capital requirement for Federal Income
Tax Expenses ought to be a negative number or, at most, zero. He bases this argument on his
assertion that, during the past five years, the Company “has received in excess of a net $90 million
of refunds” on its federal income taxes. In other words, because “refunds produce cash” for the

103
      Cities Ex. 5 (Pous Direct) at 85-88.
104
      ETI Ex. 54 (Joyce Rebuttal) at 29-32.
105
      ETI Ex. 17 (Joyce Direct) at 17, and JJJ-3.
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Company, Mr. Pous contends that the Company is seeking a positive cash working capital
requirement for cash transactions “that have not been made and are not being made.”106


          Mr. Joyce responds by disputing Mr. Pous’ contention that “refunds produce cash.”
Mr. Joyce points out that any refund from the IRS merely represents a return of the Company’s own
cash for payments previously made. Moreover, Mr. Joyce stresses that his approach for calculating
the expense lead for current federal income taxes is perfectly consistent with: (1) the requirements of
P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV)(-f-); (2) current IRS guidelines found at IRS
Publication 542; and (3) Commission precedent. Mr. Joyce further points out that, by contrast,
Mr. Pous’ approach has been consistently rejected by the RRC.107          The ALJs find Mr. Joyce’s
arguments to be more persuasive on this point and conclude that ETI has met its burden as to show
that the expense lead for current federal income tax costs it utilized in the lead-lag study is
reasonable and appropriate.


          The ALJs conclude that ETI met its burden to show that there were 39.64 expense lead days
for Affiliate Service Company Costs and 43.89 expense lead days for Other O&M Costs.


                       (c) Expense Lead and Lag – Taxes Other than Income Taxes

          This group of taxes consists of: (1) payroll-related taxes; (2) ad valorem taxes; (3) Texas
state gross receipts taxes; (4) the PUC assessment tax; and (5) Texas state franchise taxes.
Calculating from the midpoints of the work periods to the respective payment dates of the taxes,
Mr. Joyce determined that the payroll taxes had an expense lead time of 16.45 days. As to the
franchise taxes, Mr. Joyce concluded that the Company had a collection lag of 46.42 days because
the Company was required to pay the taxes in May 2010. As to the other non-payroll-related taxes,
Mr. Joyce calculated from the midpoint of the period for which the tax was assessed to the payment
date, resulting in the following expense lead days: 213.51 days for ad valorem taxes; 74.28 days for




106
      Cities Ex. 5 (Pous Direct) at 88-89.
107
      ETI Ex. 54 (Joyce Rebuttal) at 33-36, JJJ-R-1.
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Texas state gross receipts taxes; and 225.50 days for the PUC tax.108 No party challenged this
approach, and the ALJs agree.


F.        Self-Insurance Storm Reserve [Germane to Preliminary Order Issue No. 5]

          In Docket Nos. 16705 and 37744, the Commission authorized ETI to maintain a reasonable
and necessary storm damage reserve account of $15,572,000.109 As of June 30, 1996, ETI had a
positive reserve balance of $12,074,581, constituting a reduction to rate base. Over the next
15 years, ETI charged $101,670,803 to the reserve related to more than 200 storms (excluding
securitized events), but it accrued only $29,796,478 through base rates. Thus, ETI’s end-of-test-year
balance for its storm damage reserve in the present case was a negative $59,799,744.110 This
negative balance is an addition to rate base.111


          OPC and Cities argue that ETI’s current storm damage reserve negative balance should be
adjusted. OPC contends that ETI failed to prove that its storm damage expenses booked since 1996
were reasonable and prudently incurred, so it recommends disallowing all of those charges and
refunding to customers the resulting positive balance that exceeds the authorized balance.
Alternatively, OPC suggests that ETI’s negative balance be reset to its currently authorized balance,
with no refund to customers. Cities contend that ETI’s current negative storm damage reserve
balance should be reduced because it includes: unreasonable expenditures associated with a 1997
ice storm; expenses associated with former assets in Louisiana; and amounts that Cities claim should
have been treated as insurance deductibles. Cities also recommend transferring ETI’s Hurricane
Rita Regulatory Asset to the storm damage reserve. The parties’ recommendations are summarized
as follows:




108
      ETI Ex. 17 (Joyce Direct) at 18-19, and JJJ-3.
109
      Staff Ex. 4 (Roelse Direct) at 8.
110
      $12,074,581 + $29,796,478 – $101,670,803 = ($59,799,744).
111
      P.U.C. SUBST. R. 25.231(c)(2)(E).
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PUC DOCKET NO. 39896


                         Party             Reserve Balance
                         ETI               ($59,800,000)
                         Cities            ($34,051,597)
                         OPC-1             $41,871,059
                         OPC-2             $15,572,000



        1. The Effect of Prior Settled Cases

        As with the Hurricane Rita Regulatory Asset (Section V.B.), the effect of the black-box
settlements in Docket Nos. 34800 and 37744 is a significant issue concerning the storm damage
reserve. However, the parties’ positions are generally reversed from the positions taken on the
Hurricane Rita Regulatory Asset. That is, ETI now argues that its storm reserve negative balance
was resolved and approved in those settled dockets, while Cities and OPC argue that it was not.


        ETI notes that the final orders in Docket Nos. 34800 and 37744 contained “stipulated and
agreed upon” conclusions of law stating that overall total invested capital through the end of the test
year in those cases met the requirements of PURA § 36.053(a) that electric utility rates be based on
the original cost, less depreciation, of property used by and useful to the utility in providing
service.112 Then ETI cites language in P.U.C. SUBST. R. 25.231(c)(2)(E), which provides that any
deficit in a self-insurance plan will be considered an increase to rate base, or invested capital. As a
result, ETI argues, the Commission could not make a determination that a rate base expense item
was included in rate base as used and useful without also determining that the rate base expense was
prudently and reasonably incurred.113 Thus, ETI asserts, a Commission conclusion of law that
approved invested capital as meeting the requirements of PURA § 36.053(a) necessarily also
determined that an expense included in rate base was prudently and reasonably incurred. In other
words, ETI states, the “prudent and reasonable” standard is incorporated into the “used and useful”

112
   PURA § 36.053(a) provides: “Electric utility rates shall be based on the original cost, less depreciation, of
property used by and useful to the utility in providing service.”
113
   ETI cited: City of Alvin v. Public Util. Comm’n of Texas, 876 S.W.2d 346, 353-354 (Tex. App.—Austin,
1993, no pet.); see also Application of Gulf States Utilities Company for Authority to Change Rates, Docket
Nos. 7195 and 6755, 14 P.U.C. BULL. 1943 at 1969 (May 16, 1998) (“dishonest or obviously wasteful or
imprudent expenditures constitutionally can be excluded from a utility’s rate base. Such costs clearly are not
used and useful in providing serviced to the public.”).
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standard in PURA § 36.053(a).114 Therefore, ETI argues that by issuing a final orders in Docket
Nos. 34800 and 37744 with conclusions of law that ETI’s overall total invested capital met the
requirements of PURA § 36.053(a), the Commission implicitly approved the negative balances of its
insurance reserve in both prior dockets; consequently, those orders preclude litigation in the present
case of whether those expenses were prudently and reasonably incurred.115


          Cities reject ETI’s contention that the storm damage reserve balance was approved in Docket
Nos. 34800 and 37744. Cities point out that in order to comply with PURA, all final orders in rate
cases must include a conclusion of law stating that the overall total invested capital through the end
of the test year meets the requirements of PURA § 36.053(a). However, Cities contend, pursuant to
the parties’ agreements in Docket Nos. 37744 and 34800, no determination was made as to what was
included in ETI’s total invested capital in those cases. Cities explain that in Docket Nos. 37744 and
34800 Cities claimed that certain expenses were not properly included in the storm reserve balance,
while ETI argues that they were. However, neither Cities nor ETI’s recommendation was
specifically approved as part of the base rate settlement and neither of their recommended balances
may be considered as the basis for setting rates in those dockets.116 Thus, Cities argues, in such
“black box” settlements no specific storm reserve balance is approved unless expressly stated.
Cities also argues that the final orders in Docket Nos. 37744 and 34800 could just as logically be
interpreted as denying ETI’s request to include objectionable expenses in the storm damage reserve,
because both orders specified that the revenue requirement approved in those cases did not include
any prohibited expenses. Finally, Cities states that adoption of ETI’s arguments would make black-
box settlements impossible in the future.117




114
    ETI cited Docket No. 7195, 14 P.U.C. BULL. at 1969 (“the prudent investment test is embodied in
traditional ratemaking principles as expressed through PURA Sections … 41.”). PURA Section 41(a) is the
predecessor to current Section 36.053.
115
      ETI Initial Brief at 20-22; ETI Reply Brief at 17.
116
   Docket No. 37744, Final Order at Ordering Paragraph 14; Application of Entergy Gulf States, Inc. for
Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800 at Ordering Paragraph 12.
117
      Cities Reply Brief at 22-26.
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PUC DOCKET NO. 39896


          OPC makes arguments similar to Cities, and notes that no storm damage reserve amount was
either agreed to by the parties or approved by the orders in either Docket No. 34800 or Docket
No. 37744.118


          The ALJs find that the Commission did not implicitly approved all of ETI’s storm damage
expenses and its storm damage reserve balances in the final orders in Docket Nos. 34800 and 37744.
Although the orders in those settled cases contained conclusions of law the that overall total invested
capital through the end of the test year met the requirements of PURA § 36.053(a), the orders made
no findings of what the total invested capital included, and specifically there were no findings or
conclusions approving the amount of the storm damage reserve. As pointed out by Cities, in those
dockets the intervenors disputed various items in ETI’s requested storm damage reserve, but the
“black box” settlement did not specifically address those issues; consequently, it is as logical to
conclude that objectionable expenses were excluded from the storm damage reserve and from the
total invested capital as it is to conclude that the objectionable expenses were included. In
Section V.B., the ALJs conclude that ETI’s Hurricane Rita regulatory asset should be considered as
being included in the black-box settlement and final order in Docket No. 37744, even though the
settlement and order did not expressly state how the Hurricane Rita regulatory asset issue was
resolved. However, that issue involved unique circumstances and is distinguishable because PURA
§ 39.459(c) required the Commission to consider the insurance payments for the Hurricane Rita
restoration expenses in ETI’s next rate case, which was Docket No. 37744; ETI requested a true-up
in that docket of the insurance proceeds it received concerning the regulatory asset; and no party
objected to ETI’s proposed regulatory asset or its proposed amortization. In contrast, intervenors in
Docket Nos. 34800 and 37744 did object to ETI’s proposed storm damage reserve and, under those
circumstances, it is not possible to determine how the issues concerning the storm damage reserve
were resolved by the black-box settlement. Therefore, the ALJs find that the black-box settlements
and final orders in Docket Nos. 34800 and 37744 neither approved nor disapproved the
reasonableness and necessity of ETI’s storm damage expenses incurred since 1996 or ETI’s current
storm damage reserve negative balance.


118
      OPC Reply Brief at 7-8.
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          2. OPC’s Proposed Adjustment

          OPC witness Nathan Benedict testified that ETI failed to prove that any of its $101,670,803
in storm damage expense booked since 1996 was prudently incurred, so he recommended
disallowing all of those charges and refunding to customers the resulting positive balance that
exceeds the authorized balance. Removing those charges would leave ETI with a current positive
storm reserve balance of $41,871,059 (beginning balance of $12,074,581 + accruals of
$29,796,478). This balance exceeds the currently approved storm reserve balance of $15,572,000 by
$26,299,059, and Mr. Benedict proposed that this surplus be refunded to rate payers at a rate of
$1,314,953 per year for 20 years. Mr. Benedict acknowledged that some storm damage expenses
incurred by ETI since 1996 likely were reasonable and necessary. Therefore, as an alternative
proposal, Mr. Benedict suggested that ETI’s current storm balance reserve be set at the last approved
amount of $15,572,000 (i.e., without any surplus or deficit). This proposal would result in a
$75,363,744 reduction to ETI’s current storm damage reserve negative balance and rate base.119


          As discussed above, OPC disagrees with ETI’s argument that the Commission implicitly
approved these expenses in the final orders in Docket Nos. 34800 and 37744.120 Therefore, OPC
argues that ETI had to prove in the present case that the expenses were prudently incurred.
Concerning ETI’s burden of proof, OPC acknowledges that, although a utility has the ultimate
burden to prove that its proposed rates are just and reasonable, once the utility establishes a prima
facie case of prudence of a rate change, the burden shifts to the other parties to produce evidence to
rebut that presumption. Then, if the other parties rebut the presumption, the burden shifts back to
the utility to prove by a preponderance of the evidence that the challenged expenditures were
prudent. However, OPC notes, if the utility fails to establish a prima facie case, the burden of going
forward with evidence never shifts to the other parties.121 In OPC’s opinion, ETI never established a
prima facie case because ETI’s spreadsheet of storm damage expenses was excluded from evidence



119
      OPC Ex. 6 (Benedict Direct) at 6-16; OPC Initial Brief at 19.
120
      OPC Reply Brief at 7-8.
  OPC Reply Brief at 2-3, citing, Entergy Gulf States, Inc. v. Public Utility Comm’n, 112 S.W.3d 208 (Tex.
121

App. – 2003, pet. denied).
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and ETI witness Greg Wilson acknowledged on cross examination that he made no analysis of
whether ETI’s storm damage costs were reasonable and necessary.122


          ETI complains that Mr. Benedict simply sought a global rejection of more than $100 million
of expenses without any evidence to support his position, and it stressed that even Mr. Benedict
acknowledged that some of ETI’s expenses were prudently incurred. ETI also states that, in any
event, it met its burden of proof with regard to expenses booked to the storm damage reserve.


          Concerning its proof, ETI states that its burden was to make a prima facie case supporting
the prudence of its invested capital,123 and once it made that showing, the burden shifted to the
opposing parties to overcome the presumption of prudence by presenting evidence that reasonably
challenged the expenditures.124 This is the same position as OPC. ETI argues that it met its burden
to prove a prima facie case.125 ETI notes that it provided storm cost data accompanied by narrative
testimony that supported the reasonableness of ETI’s self-insurance plan; storm preparedness and
response; service quality; and cost of labor, materials, and services used to carry out distribution
activities (including system restoration). For instance, ETI states, it presented its proposed storm
reserve balance through the direct testimony of Mr. Greg Wilson126 and in the Commission’s rate
filing package.127 Mr. Wilson also explained the function of ETI’s self-insurance program,
described the $50,000 threshold to exclude minor weather events, and provided work papers
detailing the nominal and trended losses for each storm booked to the reserve since 1986, as well as
annual and total loss levels.128



122
      OPC Reply Brief at 1-5.
123
   ETI Initial Brief at 22, citing, Application of Texas Utilities Electric Company for Authority to Change
Rates, Docket No. 9300, 17 P.U.C. BULL. 2057, 2148, Order on Rehearing (Sept. 27, 1991).
124
      Docket No. 9300, 17 P.U.C. BULL. at 2148.
125
    Although ETI contended that the storm damage reserve has been approved in prior dockets, it argued that
its evidence also supported storm damage charges going back to July 1, 1996. ETI Initial Brief at 23, n. 147.
126
      ETI Ex. 14 (Wilson Direct) at 11.
127
      ETI Ex. 3 (Schedules) at Schedule B-1, line 7; Schedule WP_B-1, page 7.
128
      ETI Ex. 14 (Wilson Direct) at 5-7; WP GSW-3_1.
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            Further, ETI witness Shawn Corkran presented testimony regarding subject matters that
directly support the ability of the system to withstand storms, and ETI’s ability to reasonably and
efficiently respond to storm events, thereby supporting the conclusion that reasonable and necessary
costs are booked to the storm reserve balance. This evidence included ETI’s distribution operations,
industry-recognized comprehensive storm plans, annual storm drills, storm response and restoration
processes, distribution maintenance and asset improvement processes, service quality and
continuous improvement programs, and vegetation management practices. ETI points out that
Mr. Corkran also described how it prepares for emergency situations,129 and Mr. Corkran explained
how charges to the storm reserve are captured and recorded.130 Mr. Corkran also noted that ETI has
received either the Edison Electric Institute’s Emergency Assistance Award or Emergency Response
Award every year since 1998, which recognize ETI’s exemplary storm restoration response.131
Likewise, Mr. Corkran discussed ETI’s reliability statistics since 2000, which demonstrated a high
quality of service,132 and he provided four exhibits demonstrating that, on both per-kilowatt-hour
(kWh) and per-customer bases, ETI’s distribution O&M costs compared favorably to the costs of
other utilities.133 In ETI’s opinion, because it carried out its distribution activities in the same
efficient and cost-effective manner while performing routine activities as during storm restoration,
those metrics and reliability statistics support the reasonableness of costs booked to the reserve.134


           ETI also argues that it supported the reasonableness of the costs booked to its storm reserve
through the direct testimony of its supply chain witness, Mr. Joseph Hunter. Mr. Hunter explained
that ETI’s procurement policies and procedures are designed to streamline the acquisition of
materials and services through the use of strategic supply networks in order to achieve the lowest
reasonable cost.135 Mr. Hunter also described how the centralization of the supply chain function on

129
      Id. at 28.
130
      Id. at 93.
131
      Id. at 29.
132
      Id. at 12-29.
133
      Id., Exhibits SBC-2A, SBC-2B, SBC-2C, and SBC-2D.
134
      ETI Initial Brief at 22-24.
  ETI Ex. 16 (Hunter Direct) at 5, 9-10, and Exhibits JMH-1(Entergy Companies’ Procurement Policy) and
135

JMH-3 (Entergy Companies’ Approval Authority Policy).
SOAH DOCKET NO. XXX-XX-XXXX                  PROPOSAL FOR DECISION                               PAGE 52
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a system-wide basis provides greater leverage and buying power in the procurement of materials
and, thus, lower costs than could be achieved by ETI alone.136 Furthermore, Mr. Hunter specifically
noted that the standardization of supply chain activities “makes possible a smoother day-to-day
operation as well as rapid response to major storms or emergencies.”137


          Finally, ETI stated that it provided an extensive amount of storm reserve data through the
discovery process, which provided a basis for any interested party to investigate the reasonableness
of any particular storm response or expenditure booked to the reserve. It stressed that OPC witness
Benedict acknowledged that ETI provided 420 pages and over 22,220 lines of detail reflecting every
charge to the storm reserve over the last 15 years,138 which specified the month, year, state, project
code, work order type, function, storm name, account number, resource code, resource code
description, and amount.139 Therefore, ETI argues that it made a prima facie case regarding its
storm reserve through the presentation of narrative testimony, schedules, work papers, and expense
detail and, accordingly, the burden shifted to parties seeking to disallow the expenses allocated to
the storm damage reserve to present evidence that reasonably challenges their prudence.140 Yet, ETI
contends, OPC did not challenge any specific expenditure booked to the reserve other than the 1997
ice storm expenses discussed later. Therefore, ETI argues that it met its prima facie burden and
OPC’s proposed disallowance of either $101,670,803 or $75,363,744 should be denied.141


          Although it is a close call, the ALJs find that ETI established a prima facie case that its storm
damage expenses incurred since June 30, 1996, were prudently incurred. A prima facie case is a low
burden. It is not the same as a preponderance of the evidence. Rather, as stated in Town of Fairveiw
v. City of McKinney, prima facie evidence “is merely that which suffices for the proof of a particular




136
      ETI Ex. 16 (Hunter Direct) at 17.
137
      Id. at 18 (emphasis added).
138
      Tr. at 1703.
139
      Tr. at 1704.
140
      Docket No. 9300, 17 P.U.C. BULL. at 2147.
141
      ETI Initial Brief at 22-26; ETI Reply Brief at 16-19.
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fact until contradicted and overcome by other evidence.”142 Similarly, Black’s Law Dictionary
defines a prima facie case as sufficient evidence “to allow the fact-trier to infer the fact at issue and
rule in the party’s favor.”143


          Except for expenses incurred with the 1997 ice storm, ETI did not present any testimony that
explicitly stated that the expenses included in its storm damage reserve were prudently incurred.
However, ETI did present sufficient other evidence that at least allows the ALJs to infer that the
expenses were prudently incurred. As noted above, a reasonable inference from the evidence
presented is sufficient to establish a prima facie case. ETI witness Gregory Wilson presented
testimony about the background of the storm damage reserve and about ETI’s yearly major storm
damage losses, although OPC is correct that he did not explicitly evaluate or determine whether
ETI’s expenses were reasonable and necessary.144 In addition, OPC witness Benedict provided
testimony that ETI has booked $101,670,908 to the storm damage reserve since 1996,145 and that
ETI’s $50,000 threshold is a means of excluding from the reserve small storm-related expenses that
ETI could anticipate as routine O&M expense and which should be excluded from the storm damage
reserve.146 ETI presented testimony that it had not recorded storm damage expense to both the storm
damage reserve and to O&M expense,147 and Mr. Benedict agreed that he had no information to
contradict this148 or that any securitized costs were charged to the storm damage reserve.149
Although the document itself was excluded from evidence, Mr. Benedict testified that ETI provided
him with a 420-page spreadsheet covering all of ETI’s storm damage expenses back to 1996,
including the month, year, state, project code, project name, work order type, function, storm name,
account number, resource code, resource code description, and amount.150 In addition, ETI provided

142
      271 S.W.3d 461, 467 (Tex. App. – Dallas 2008 pet. denied).
143
      Black’s Law Dictionary, 8th Ed. (2004).
144
      ETI Ex. 14 (Wilson Direct) at Ex. GSW-3.
145
      OPC Ex. 6 (Benedict Direct) at 7-8.
146
      Tr. at 1694.
147
      ETI Ex. 72 (Wilson Rebuttal) at 2-3.
148
      Tr. at 1695-1696.
149
      Tr. at 1698.
150
      Tr. at 1704.
SOAH DOCKET NO. XXX-XX-XXXX                  PROPOSAL FOR DECISION                             PAGE 54
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other testimony described previously concerning its distribution operations, storm plans, storm
response operations, purchasing procedures, and the like.


          ETI did not present a witness who specifically testified that all of its storm damage expenses
booked to the storm damage reserve were prudently incurred, except for expenses related to the 1997
ice storm. Such testimony would have been more helpful than the evidence ETI relied upon.
Nevertheless, the burden of establishing a prima facie case does not require such direct testimony, if
a fact can be reasonably inferred from other evidence presented. The ALJs reiterate that it is a close
call, but they find that ETI did present sufficient evidence to infer that the expenses charged to the
storm damage reserve were prudently incurred. At that point, the burden shifted to OPC to produce
evidence to challenge specific expense items included in the storm damage reserve, but OPC did not
present any such evidence except for the items discussed below. Therefore, the ALJs recommend
that the Commission not adopt either of OPC’s recommended denials of expenses contained in ETI’s
storm damage reserve.


          3.   1997 Ice Storm

          ETI’s proposed negative storm reserve balance includes $13,014,379 in expenditures
associated with a 1997 ice storm. Cities and OPC contend that this expense should be excluded
from the storm balance reserve.


          Cities witness Pous explained that ETI first requested to include the 1997 ice storm expense
in the storm damage reserve as a post test year adjustment in its 1995-1996 test-year rate case,
Docket No. 16705. The Commission denied the requested post test year adjustment and stated that
the expense should be considered in ETI’s next rate case. Thereafter, ETI had a series of rate cases
(Docket No. 20150 – 1998 rate case; Docket No. 30123 – 2004 rate case; Docket No. 34800 – 2007
rate case; Docket No. 37744 – 2009 rate case) in which intervenors challenged the 1997 ice storm
expenses, but those cases all settled or were otherwise concluded without any express decision
concerning the prudence of ETI’s 1997 ice storm expenses.151 Mr. Pous testified that these expenses


151
      Cities Ex. 5 (Pous Direct) at 49-55.
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are now appropriately at issue in the present case, and he recommended that the entire balance be
excluded from the storm damage reserve. He pointed out that in Docket No. 18249, the Commission
found that ETI’s poor quality of service exacerbated the extent of damage caused by the storm, and
it found that the response efforts were uneven and delayed and could have been more effective if
ETI had a better communication and management program in place.152 Mr. Pous also contended that
in the present case ETI failed to prove that any portion of the 1997 Ice Storm expenses were
reasonable.153


          Thus, Cities argue that the Commission has already determined that ETI’s negligence was a
major factor in the extent and duration of the outages,154 so no expenses associated with the 1997 ice
storm should be eligible for recovery from customers through the storm damage reserve. In response
to ETI’s argument that it was already penalized for these issues in Docket No. 18249 through a
reduction to the allowed ROE, Cities argue that the Commission did not absolve ETI from
responsibility for damage caused by ETI’s poor service quality, and ETI’s customers should not be
ordered to pay for expenses that were caused by ETI’s negligence.155


          OPC makes the same arguments as Cities concerning the 1997 ice storm expenses.156


          ETI argues that, due to quality of service issues related to the 1997 ice storm, the
Commission reduced Entergy Gulf States, Inc.’s (EGSI) ROE by 60 basis points in Docket
No. 18249 and subjected EGSI to significant spending requirements and quantified performance
guarantees. In ETI’s opinion, it would be inequitable to now penalize ETI a second time for the
same issues. Moreover, ETI argues that it established that its expenses were reasonable and
necessary. ETI witness Shawn Corkran testified that the 1997 ice storm was the most destructive


152
   Entergy Gulf States, Inc. Service Quality Issues Severed From Docket No. 16705, Docket No. 18249,
Final Order at FoF 97, 98, & 102 (Apr. 21, 1998).
153
      Cities Ex. 5 (Pous Direct) at 56-59; see Cities Initial Brief at 18-19.
154
   Cities Initial Brief at 18 (“The Company’s failure to clear the limbs before the storm was a major factor in
the number and duration of outages experienced by customers.”).
155
      Cities Reply Brief at 28-30.
156
      OPC Ex. 6 (Benedict Direct) at 12; OPC Initial Brief at 16; OPC Reply Brief at 7-10.
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winter storm ever to hit the EGSI/ETI system, with about 3,400 miles of distribution lines and
560 miles of transmission lines de-energized during the storm’s peak. A large part of the restoration
effort involved clearing broken and fallen trees and tree limbs from lines. Mr. Corkran reviewed all
of the costs incurred in response to the 1997 ice storm and stated that they were reasonable and
necessary to reliably restore service to customers as quickly as possible after the storm. He provided
an exhibit with a detailed breakdown of labor, materials, transportation, lodging, and other expenses
incurred. In his opinion, all of these costs charged to the storm damage reserve, totaling
$13,014,379, were reasonable, necessary, and prudently incurred.157


          The ALJs recommend that the Commission authorize ETI to include in the storm damage
reserve its $13,014,379 in expenditures associated with the 1997 ice storm. ETI established that
those expenses were reasonable and necessary to repair the damage and restore power to its
customers. ETI witness Mr. Corkran provided detailed testimony concerning the seriousness of the
storm and the resulting expenses incurred for repair work and restoration of power to customers.158


          In contrast, Cities and OPC did not challenge any specific item in these restoration expenses.
Instead, they relied upon the Commission’s findings in Docket No. 18249 that ETI’s deficient
maintenance exacerbated the amount of damage caused by the storm. However, in that docket the
Commission also reduced ETI’s ROE by 60 basis points due to poor service issues, including
deficient preventative maintenance. The Commission made the reduction in ROE retroactive and
required ETI to make refunds to customers. Likewise, in that docket the Commission found that the
ice storm was severe and that significant damage would have occurred even with exemplary
vegetation management and other preventative measures. It is not feasible to accurately determine
now what portion of ice storm damage that occurred 15 years ago was caused by preventative
maintenance issues.


          The ALJs conclude, however, that the Commission’s retroactive reduction of ETI’s ROE in
Docket No. 18249 in part compensated ratepayers for the poor service issues that exacerbated the

157
      ETI Ex. 48 (Corkran Rebuttal) at 2-12.
158
      ETI Ex. 48 (Corkran Rebuttal) at 2-12 and Ex. SBC-R-1.
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storm damage. Nevertheless, once the ice storm occurred, ETI had to take appropriate action to
repair the damage and restore service. ETI has established the expenses incurred in those efforts
were reasonable and necessary, and the ALJs find that they should be included in the storm damage
reserve. Therefore, the ALJs recommend that the Commission deny Cities and OPC’s proposed
adjustment.


          4. Jurisdictional Separation Plan Allocation

          Cities complained that ETI’s storm damage reserve deficit includes $12,498,325 in costs that
belong to Louisiana jurisdiction customers but were incorrectly transferred to Texas customers
during implementation of the Jurisdiction Separation Plan.                  Cities explain that before the
jurisdictional separation of EGSI into ETI and Entergy Gulf States Louisiana, LLC (EGSL), the
transmission investment and expense associated with maintaining the transmission system, including
storm restoration costs, was allocated between the Texas and Louisiana retail jurisdictions. In the
jurisdictional separation of EGSI into ETI and EGSL, the transmission system investment was split
between each company based upon a situs basis. The transmission facilities in Texas were
transferred to ETI and the transmission facilities in Louisiana were transferred to EGSL. After the
jurisdictional separation, ETI and EGSL were each responsible for future O&M expense, including
storm restoration expense, associated with their respective transmission investments.


          Cities claim that in the present case ETI has attempted to reverse the allocation of expenses
incurred on behalf of Louisiana customers before the jurisdictional separation and to charge those
expenses to Texas customers through the storm damage reserve. In Cities’ opinion, any expense that
was allocated to Louisiana customers prior to the jurisdictional separation was properly charged to
Louisiana customers. Cities argue that ETI may not now reverse expenses allocated to Louisiana
customers and charge them to Texas customers solely on the basis that ETI acquired the
transmission investment located in Texas.159




159
      Cities Ex. 5 (Pous Direct) at 59-60; Cities Initial Brief at 19-20.
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        In response, ETI witness Considine explained that an analysis of storm reserve charges was
preformed prior to the jurisdictional separation to determine if storm charges were incurred for
Texas or Louisiana property. The reclassification of certain charges was made as a result of that
analysis, which is in evidence, to properly reflect the state in which the storm charges were incurred.
The largest charge assigned to ETI through this analysis was a $10,652,130 charge related to project
“E2PPSJ8291 Trans EGSI-TX Hurricane Rita 9-24-05,” which expressly related to damages to the
Texas portion of the former EGSI transmission system. Similarly, costs were assigned from ETI to
EGSL for projects such as “E2PPSJ8296 Trans. Hurricane Katrina - EGSI-La” and “E2PPSJ8302
Trans EGSI-LA Hurricane Rita 9-24-05,” that clearly related to assets located in Louisiana. In other
words, prior to the separation, the Texas portion of the storm damage reserve could include charges
for restoration work performed on assets located in Louisiana, and vice versa. The analysis
conducted pursuant to the separation re-aligned the charges to the jurisdiction where the assets are
located. In that way, ETI argues, neither jurisdiction has charges in its storm reserve balance for
assets located in the other jurisdiction. In short, ETI argues that the assets and liabilities following
the separation have been properly assigned and no improper cost shifting occurred.160


        The ALJs recommend that the Commission deny Cities’ proposed adjustment. ETI offered
evidence to explain how its reclassification study reassigned various costs from the Texas
jurisdiction to Louisiana, as well as from the Louisiana jurisdiction to Texas. This study resulted in
more expenses from Louisiana being reassigned to the Texas jurisdiction than from Texas to
Louisiana, but Cities offered no evidence to explain why the study was flawed or why the
reassignments were in error. The ALJs found ETI’s evidence to be credible and that it supported the
jurisdictional allocation of these expenses as proposed by ETI.


        5. $50,000 Reserve Threshold

        Cities witness Pous also proposed a $10,950,000 reduction to ETI’s negative storm damage
reserve balance due to ETI including in the reserve the first $50,000 of expense for each separate
storm event. Mr. Pous asserted that this amount is equivalent to a deductible for insurance purposes

160
    ETI Ex. 46 (Considine Rebuttal) at 25 and Ex. MPC-R-3 at 25; ETI Initial Brief at 19-36; ETI Reply Brief
at 20-21.
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and should have not been charged to the reserve. Cities note that P.U.C. SUBST. R. 25.231(b)(1)(G)
requires that a storm reserve only collect for “property and liability losses which occur, and which
could not have been reasonably anticipated and included in operating and maintenance expenses.”
Because of ETI’s low $50,000 threshold, Cities contend, ETI has recorded to the storm reserve
expenses associated with 219 different weather events in the past 15 years. This equates to
approximately 14.6 weather events per year, or 1.2 weather events per month, on average. In Cities’
view, ETI’s booking to the storm damage reserve of all expenses associated with a weather event
exceeding $50,000 – including the first $50,000 – is inconsistent with P.U.C. SUBST.
R. 25.231(b)(1)(G). Cities argue that ETI may not reasonably claim that such a recurring expense is
“not reasonably anticipated” to qualify it for the storm reserve. Cities proposed adjustment is based
on $50,000 for each of the 219 storm events, for a total of $10,950,000. In addition, based on the
nature of ETI’s recurring storm expense, Cities also recommend that the deductible amount be
increased to $500,000, which Cities stated is consistent with the storm reserve treatment afforded to
other utilities in Texas.161


          ETI witness Gregory Wilson testified that Mr. Pous misconstrued the $50,000 trigger when
he treated it as a deductible. Mr. Wilson explained that if a storm causes $50,000 or less in damage,
the expenses are not charged to the storm damage reserve. However, if a storm causes more than
$50,000 in damage, all of the expenses are charged to the reserve. He noted that if the $50,000 were
treated as a deductible, then that amount would still be charged to O&M whenever storm damage
exceeded the $50,000 threshold. But, under the current arrangement, when storm damage exceeds
$50,000 all of the expenses are charged to the storm damage reserve, and the first $50,000 is not
charged to O&M. Therefore, no double recovery occurs. Moreover, ETI argues that Cities’
proposed retroactive removal of these amounts from the reserve would constitute a disallowance of
costs without any finding of imprudence, as well as impermissible retroactive ratemaking. ETI also
contends that even if the Commission were to implement Mr. Pous’s recommendation prospectively,
it would require a corresponding increase in ETI’s O&M costs. Therefore, ETI disagreed with




161
      Cities Ex. 5 (Pous Direct) at 61-63; Cities Initial Brief at 20-21.
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Cities’ recommendation to reduce the current balance of the storm damage reserve by $10,950,000
or to change the current level of the threshold.162


          The ALJs find that Cities’ proposed adjustment to ETI’s storm damage reserve is not
warranted. ETI explained that the $50,000 threshold amount was included in the storm damage
reserve whenever storm restoration expenses exceeded the threshold, but that amount was not
included in O&M expense. Accordingly, no double recovery has occurred, and Cities presented no
other valid reason to disallow the allocation of these expenses to the storm damage reserve.
Therefore, the ALJs recommend that the Commission deny Cities’ proposed $10,950,000 adjustment
to ETI’s current storm damage reserve balance. As a policy matter, the Commission may choose to
increase ETI’s threshold on a prospective basis to some higher amount, as recommended by Cities,
but the evidence presented by the Cities on this issue was not sufficient for the ALJs to make such a
recommendation.


          6. Hurricane Rita Regulatory Asset

          As discussed in Section V.B., Cities recommend an adjustment to the Hurricane Rita
regulatory asset, and they recommended the adjusted balance be moved to the storm damage reserve.
For the reasons stated in Section V.B., the ALJs recommend that the Commission not adopt Cities’
proposal to move the Hurricane Rita regulatory asset to the storm damage reserve.


          7. Conclusion

          In conclusion, the ALJs find that ETI’s storm damage expenses since 1996 and its storm
damage reserve balance were not approved by the Commission as a result of the black-box
settlements in Docket Nos. 34800 and 37744. The ALJs also find that ETI established a prima facie
case concerning the prudence of its storm damage expenses incurred since 1996 and that
intervenors’ proposed adjustments should be denied. Therefore, the ALJs recommend that the
Commission approve ETI’s test-year-end storm reserve balance of negative $59,799,744.



162
      ETI Ex. 72 (Wilson Rebuttal) at 2-3; EIT’s Initial Brief at 27-28; ETI Reply Brief at 21-22.
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G.         Coal Inventory

           ETI is the partial owner of two coal-fired power generating facilities. It owns a 29.75
percent interest in Nelson 6, a 550 megawatt (MW) unit located in Westlake, Louisiana (Nelson),
and a 17.85 percent interest in Big Cajun II, Unit 3, a 588 MW unit located in New Roads, Louisiana
(BCII/U3). EGSL is the majority owner and operator of Nelson and is responsible for the supply
and delivery of coal to that facility. A third party, LaGen, is a co-owner of BCII/U3, and is the
operator of the plant. Pursuant to a joint operating agreement between the co-owners, LaGen is
responsible for the acquisition and delivery of coal to BCII/U3. The coal for both units comes, via
train, from minefields in Wyoming.163


           Entergy has adopted a “Coal Inventory Policy” at Nelson to ensure that a sufficient coal
inventory is always maintained on-site to help mitigate transportation and unit operating risks. The
policy calls for, among other things, a 12-month average inventory target of a 43-day supply of coal.
Because Entergy is not the operator of BCII/U3, it does not have ultimate control over the coal
inventories at that unit. Pursuant to the joint operating agreement for that unit, however, each year
ETI nominates for the next calendar year the level of coal to be delivered for its account at BCII/U3.
ETI’s nomination process is targeted to ensure an end-of-year inventory target of a 43-day supply of
coal.164


           In its application, ETI includes a coal inventory amount in its rate base that is based upon the
average inventories at Nelson and BCII/U3 for the 13 months ending in June 2011.165 The average
coal inventory at Nelson was 384,860 tons, representing approximately 48 days of inventory,
assuming an average daily burn rate of 8,000 tons. The total proposed dollar amount for the coal
inventories at both facilities is $9,846,037. Of that total, the Nelson portion is $6,040,926, and the




163
      ETI Ex. 33 (Trushenski Direct) at 3-4.
164
      ETI Ex. 33 (Trushenski Direct) at 30-31.
165
    ETI Ex. 68 (Trushenski Rebuttal) at 2. Notably, the amount ETI is seeking in its Rate Base is calculated
upon a 13-month average ending June 2011 (the last month of the Test Year), even though that amount is
slightly less than the 12-month average for the Test Year.
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BCII/U3 portion is $3,805,111.166 ETI witness Ryan Trushenski, the Manager of the Solid Fuel
Supply Group for ESI, testified that the coal inventory levels that were maintained at Nelson and
BCII/U3 during the test year were reasonable and the costs incurred to maintain those levels were
reasonable.167


          Cities do not challenge the reasonableness of the Company’s 43-day inventory targets.
Rather, Cities point out that the size of the actual inventory that was maintained on-site at Nelson
during the Test Year exceeded the Company’s inventory target level. Therefore, Cities contend that
customers should not be forced to pay for inventory levels exceeding a 43-day supply (the amount
that the Company determined, through its Coal Inventory Policy, to be a reasonable and necessary
inventory to maintain on-site). According to Cities’ witness, Karl Nalepa, a 43-day inventory of
coal at Nelson would equate to 340,000 tons. He recommends that the value of a 43-day supply of
coal be included in the rate base, but that $1,451,415 be excluded from the rate base to account for
inventory at Nelson that was in excess of the 43-day supply.168


          The evidence shows that the Company’s inventory “target” was a 43-day supply, while
actual inventories during the Test Year averaged around a 48-day supply. Mr. Trushenski pointed
out, and the ALJs concur, that the 43-day “target” was never intended to represent a hard and fast
figure from which no deviations could be allowed. Rather, the target merely represents an
operational planning tool. Moreover, there are many real-world factors – such as train cycle times,
coal burn rates, and so on – that can cause the actual coal inventory to fluctuate over time.169 The
ALJs conclude that the 48-day coal inventory was acceptably close to the 43-day target and was not
unreasonable. The total proposed dollar amount for this coal inventory is $9,846,037. The ALJs
conclude that the full value of the coal inventory was reasonable and should be included in rate base.




166
      ETI Ex. 68 (Trushenski Rebuttal) at 2, and 3 at WP/P RB 4.2.
167
      ETI Ex. 33 (Trushenski Direct) at 30-31.
168
      Cities Ex. 6 (Nalepa Direct) at 28-29, 6C and 6E.
169
      ETI Ex. 68 (Trushenski Rebuttal) at 4.
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H.         Spindletop Gas Storage Facility

           ETI relies upon a variety of fuel types to generate electricity. A major fuel component is
natural gas. However, energy generated from natural gas typically has the highest marginal cost
and, therefore, it is most often the last resource deployed to generate electricity. The fluctuation of
natural gas demand resulting from the changes in instantaneous demand is known as “swing.”
Although a portion of the system’s base load requirement is met with natural gas, the primary role of
natural gas is as a swing fuel on the system.170


           Since 2004, ETI has owned and used the Spindletop Facility. ETI, through a third-party
operator, uses the Spindletop Facility to maintain a natural gas inventory that can be used to supply
ETI’s Sabine Station and Lewis Creek power generating facilities. Spindletop consists of two
salt-dome storage caverns (and associated equipment) located near Sabine Station.171                 The
Spindletop Facility serves a function similar to that of a city water tower – it enables ETI to buy
natural gas at one point in time, store it, and use it at some future point when supplies are not
available elsewhere or when peak needs cannot otherwise be met. ETI maintains that the primary
benefit of the Spindletop Facility is that it provides: (1) supply reliability; and (2) swing flexibility.
“Supply reliability” means that the facility can provide a reliable supply of gas for Sabine Station
and Lewis Creek during potential gas supply curtailments, such as can occur during hurricanes,
freezes, or other unusual events. In a worst-case scenario, the Spindletop Facility is capable of
providing 100 percent of the fuel requirements for all five units at Sabine Station and one Lewis
Creek unit for four days at 70 percent of capacity. The Spindletop Facility also allows the Company
to avoid almost all intra-day gas purchases for Sabine Station. This is important because intra-day
purchases tend to be more expensive than longer-term purchases.172


           Because major supply disruptions are more likely to occur during hurricane season and
during the winter, ETI manages its gas inventories conservatively during the period from June
through March in order to ensure that it can provide a reliable supply of fuel to meet peak generation


170
      ETI Ex. 28 (McIlvoy Direct) at 7.
171
      Id. at 31.
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loads for four consecutive days. During the remainder of the year, ETI will consider withdrawing
gas from the Spindletop Facility when the current day spot market price is higher than the
replacement cost for the gas, as determined by future market indicators. Conversely, ETI injects gas
into the Spindletop Facility when the cost of gas in the current market is less than the price of gas in
the futures market.173 For these various reasons, ETI witness Karen McIlvoy, who is employed as
the manager of ESI’s Gas & Oil Supply Group, testified that that Spindletop Facility is used and
useful for providing reliable, economical service to ETI’s customers.174 ETI witness Devon Jaycox,
who is employed as the manager of ESI’s Operations and Planning Group, testified that the
Company is always evaluating how much reliability the Spindletop Facility can provide as compared
to other options. He explained that, at Sabine Station, there is no other option that can provide ETI
with the same level of reliability and flexible swing service that the Spindletop Facility provides.175


           Cities are critical of the Spindletop Facility, contending that the costs of operating it
outweigh the benefits gained from it. No other party challenged ETI’s use of the Spindletop
Facility. Cities’ witness Karl Nalepa testified that it costs ETI $13,219,097 per year to operate the
gas storage facility, whereas the Company could achieve the same supply reliability and swing
flexibility benefits it gets from the Spindletop Facility through other gas supply options at a cost of
only $1,724,659, thereby saving its customers $11,494,438. Thus, Mr. Nalepa stated that it is
imprudent for ETI to continue operating the Spindletop Facility.176


           Mr. Nalepa testified that no other Entergy operating company owns or leases its own gas
storage facility, yet those other companies are able to satisfy their needs for supply reliability and
swing flexibility through other methods, such as existing gas supply and transportation contracts, at
much lower costs. According to Mr. Nalepa, those other companies obtain supply reliability and
swing flexibility through the use of monthly, daily, and intra-day natural gas supply contracts. In


172
      ETI Ex. 28 (McIlvoy Direct) at 32-33; ETI Initial Brief at 39, n. 264.
173
      ETI Ex. 28 (McIlvoy Direct) at 33-34.
174
      Id. at 37.
175
      Tr. at 966.
176
      Cities Ex. 6 (Nalepa Direct) at 18-20; Cities Ex. 6B (Errata No. 2).
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support of this claim, he pointed to one of the operating companies, EGSL, as an example. He
pointed out that EGSL has no firm transportation contracts, no firm supply contracts, and no fuel oil
back-up at its generating plants. Thus, Mr. Nalepa stated that the only cost incurred by EGSL for
reliability and flexibility is the commodity cost of the natural gas it purchases. Mr. Nalepa testified
that EGSL achieves the same level of service as ETI without incurring the large cost of the
Spindletop Facility.177


          Mr. Nalepa asserted that the long-term gas supply contract that ETI recently entered into
with Enbridge Pipeline, L.P. (the Enbridge Contract) will help provide the Company with increased
supply reliability because the gas supplied by Enbridge will come from production areas that are less
susceptible to hurricane-related disruptions. Mr. Nalepa also noted that ETI could meet its swing
flexibility requirements through use of spot gas purchases, its operational balancing agreement with
the TETCO pipeline, and other pipeline companies, such as the Copano Pipeline that serves Lewis
Creek.178


          Mr. Nalepa also disputed ETI’s contention that the Spindletop Facility serves as a valuable
protection against extreme events such as hurricanes, by noting that the Spindletop Facility was out
of service for almost two weeks in 2005 following Hurricane Rita.179


          As noted above, Mr. Nalepa testified that it cost ETI $13,219,097 to operate the Spindletop
Facility in the Test Year. Mr. Nalepa estimated that the sum of the Test Year withdrawals of gas
from the Spindletop Facility equaled 8,560,604 MMBtu. He then divided his total estimated cost of
the facility ($13,219,097) by his total estimated withdrawals of gas (8,560,604 MMBtu) to calculate
an “all-in per unit rate” of $1.54 per MMBtu. He asserted that, by contrast, transportation costs on
various gas pipelines connected to Sabine and Lewis Creek ranged from $0.025 to $0.22 per
MMBtu. Mr. Nalepa estimated $0.18 per MMBtu as the average replacement cost that ETI would
incur in transportation contracts if it were to stop using the Spindletop Facility and achieve the same


177
      Cities Ex. 6 (Nalepa Direct) at 22-23.
178
      Cities Ex. 6 (Nalepa Direct) at 25.
179
      Id. at 23-24.
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level of supply reliability and swing flexibility through the use of gas supply contracts. By
multiplying $0.18 times 8,560,604 MMBtu, he estimated that the benefits of the Spindletop Facility
could have been achieved through other means at a cost of only $1,724,659. Thus, Mr. Nalepa
recommended that $7,794,202 should be removed from ETI’s base rate, and $5,424,895 should be
excluded as an eligible fuel expense.180


          ETI disagrees with essentially all of Mr. Nalepa’s points and responds to his testimony on a
number of fronts. Perhaps foremost, ETI points out that Mr. Nalepa’s main premise – that ETI’s
customers pay all the costs of the Spindletop Facility while the other Entergy operating customers
avoid those costs – is simply incorrect. According to ETI witnesses, 57.50 percent of the costs
associated with the Spindletop Facility are billed to EGSL as part of the MSS-4 billing process
between ETI and EGSL for its “legacy plants,”181 and another 2.4 percent of the costs are passed on
to other Entergy operating companies through the MSS-3 agreement. Only 40.1 percent of the
Spindletop Facility costs are borne by ETI customers.182 Thus, Mr. Nalepa’s calculations greatly
overstate the costs of the Spindletop Facility that are borne by ETI customers and greatly understate
the costs that are borne by EGSL customers. ETI witness Considine also pointed out that the
Commission has consistently and repeatedly concluded that the Spindletop Facility is used and
useful and, therefore, has allowed ETI and its predecessors to recover the costs associated with the
Spindletop Facility.183


          Ms. McIlvoy also testified that, contrary to Mr. Nalepa’s testimony, the conditions under
which the other Entergy operating companies operate are so different from the conditions under
which ETI operates that it makes no sense to assume they have similar supply reliability and swing
flexibility needs. For example, EGSL and ETI both own roughly the same generating capacity from


180
      Id. at 24-27; Cities Ex. 6B (Errata No. 2).
181
   The legacy plants are the four power generating plants that were owned by Entergy Gulf States, Inc. –
Lewis Creek, Sabine Station, Nelson, and Willow Glen. When EGSI was broken into ETI and EGSL in 2007,
ETI became the owner of Lewis Creek and Sabine Station, while EGSL became the owner of Nelson and
Willow Glen. ETI Ex. 60 (McIlvoy Rebuttal) at 5-6; ETI Ex. 46 (Considine Rebuttal) at 3.
182
      ETI Ex. 46 (Considine Rebuttal) at 3-4; ETI Ex. 60 (McIlvoy Rebuttal) at 18-19.
183
      ETI Ex. 46 (Considine Rebuttal) at 3-4.
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gas-powered plants – 2,378 MW for EGSL versus 2,295 MW for ETI. However, the ETI plants are
operated at a much higher capacity than the EGSL plants. During the Reconciliation Period, EGSL
burned much less natural gas than did ETI – 63,420,554 MMBtu burned at the EGSL plants versus
144,538,535 MMBtu burned at the ETI plants. Moreover, EGSL has four gas-powered plants while
ETI has only two. Of EGSL’s four plants, two (Calcasieu and Ouachita) use combined cycle gas
turbine technology. This gives them a quick-start and shut-down capability, allowing them to be
operated primarily only at peak demand times. Thus, according to Ms. McIlvoy, Mr. Nalepa’s
premise – that because EGSL is able to reliably operate its gas-fired facilities without gas storage,
ETI should be able to do so as well – makes no sense. Because ETI burns a vastly larger amount of
natural gas than EGSL, its need for supply reliability and swing flexibility is much greater.184


          Ms. McIlvoy also disputed Mr. Nalepa’s assertion that ETI could use the Enbridge Contract
and call options to provide the Company with sufficient supply reliability. She noted that the
maximum amount of gas deliverable under the Enbridge Contract is insufficient to run the ETI
plants even at minimum load. By contrast, the Spindletop Facility is capable of supplying all Sabine
Station units and one unit at Lewis Creek for four days at 70 percent capacity.       Moreover, the
Enbridge Contract will expire, whereas the Spindletop Facility can be operated indefinitely.
Ms. McIlvoy explains that the use of call options is not viable because a call option must be
delivered “ratably,” meaning the gas must be delivered at a constant, even rate throughout the
delivery period. In order to have gas available to meet peak needs in the absence of the Spindletop
Facility, ETI would have to exercise call options for a maximum delivery, but it would not need all
of the gas delivered at off-peak times of the day.185


          ETI witness Jaycox disputed Mr. Nalepa’s premise that ETI could use call options to ensure
reliability. According to Mr. Jaycox, “call options are cheaper than storage, but there’s no
comparison” between the amount of reliability that they provide as compared to the Spindletop
Facility.186 Mr. Jaycox also explained that, due to their geographic location and the limited import

184
      ETI Ex. 60 (McIlvoy Rebuttal) at 3-8.
185
      ETI Ex. 60 (McIlvoy Rebuttal) at 8-12.
186
      Tr. at 969.
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capability to the ETI service area, Sabine Station and Lewis Creek are considered particularly
critical, thereby increasing the need for reliability at those plants.187


          When Mr. Nalepa calculated ETI’s cost of achieving supply reliability and swing flexibility
without the use of the Spindletop Facility, he estimated it would cost only $1,724,659. He did so, in
part, by assuming that a five-day 35,000 MMBtu/day call option would cost ETI $26,250.
Ms. McIlvoy asserted that it is not reasonable to assume that all options would cost as little as
$26,250. Based upon her calculations, ETI would have to purchase 14 five-day 35,000 MMBtu/day
call options per month to achieve supply reliability. She posited that, based upon the laws of supply
and demand, the more call options ETI has to purchase, the higher the cost of those options would
be. She also pointed out that Mr. Nalepa’s proposed use of call options would require ETI to spend
hundreds of thousands of dollars each month to purchase call options that it would never exercise.
According to Ms. McIlvoy, it is unclear from Commission precedents whether ETI would be entitled
to recover the costs of these un-exercised options.188


          The evidence establishes that the Spindletop Facility is critical to providing reliability and
swing flexibility to ETI’s Texas plants. The ALJs conclude that the Spindletop Facility is a used and
useful facility providing reliability and swing flexibility to ETI’s customers at a reasonable price,
and Cities’ arguments to the contrary lack merit.


I.        Short Term Assets

          In its application ETI requested that, as short term assets, the following amounts be included
in the rate base: prepayments in the amount of $7,218,037; materials and supplies in the amount of
$29,252,574; and fuel inventory in the amount of $53,759,975. These amounts were derived using
13-month averages ending June 2011.189 Staff witness Anna Givens agrees with the approach of
using 13-month averages to determine the appropriate amounts for short term assets. However, she
recommends using the 13-month period ending December 2011, because it is the most recent

187
      Tr. at 975, 986-87.
188
      ETI Ex. 60 (McIlvoy Rebuttal) at 12-15.
189
      ETI Ex. 3 at Sched. B-1.
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information available. Using this approach, Ms. Givens recommends that, as short term assets, the
following amounts be included in the rate base: prepayments at $8,134,351 ($916,313 more than
ETI’s request); materials and supplies at $29,285,421 ($32,847 more than ETI’s request); and fuel
inventory at $52,693,485 ($1,066,490 less than ETI’s request).190 ETI does not oppose Staff’s
recommendation on this issue. No party has a criticism of Staff’s estimates as to prepayment,
materials and supplies, and fuel inventory, nor do the ALJs. Accordingly, the ALJs recommend
adopting the numbers proposed by Staff.


J.         Acquisition Adjustment

           In its application, ETI included an adjustment of $1,127,778 for an “electric plant
acquisition.”191 The proposed adjustment, which relates to costs incurred by ETI when it acquired
the Spindletop Facility, consists of closing costs of $211,209 and legal and internal costs of
$916,568.192 ETI witness Considine explained that, prior to December 2009, the same amounts were
included in the Electric Plant in Service (FERC Account 101). On January 11, 2010, FERC issued
Opinion No. 505 in FERC Docket No. ER07-956-00 and ordered the Company to transfer the
amounts above from Account 101 to FERC Account 114, Electric Plant Acquisition Adjustments.
He also pointed out that the costs were included in ETI’s filed rate base amounts in Docket Nos.
34800 and 37744.193 Mr. Considine contended that these amounts should remain in rate base
because they represent costs incurred by ETI for the purchase of a viable asset that benefits its retail
customers. He pointed out that the amounts have previously been included in the Company’s rate
base, but the only thing that has changed is that the amounts were previously allocated to a different
account. ETI argues that the fact that the costs were approved as part of rate base in two previous
ETI dockets verifies that they were “reasonable, prudently incurred, and properly capitalized.”194




190
      Staff Ex. 1 (Givens Direct) at 31-32.
191
      ETI Ex. 3 at Sched. C-1.
192
      ETI Ex. 46 (Considine Rebuttal) at 4.
193
      Id. at 4-5.
194
      ETI Initial Brief at 43.
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Thus, ETI contends it would be inappropriate to penalize it because of an accounting technicality
imposed upon it by FERC.195


           Staff advocates the removal of the entire electric plant acquisition adjustment from rate base,
contending that, “[a]s a rule, the rate base component for plant in service includes only the original
cost, net of accumulated depreciation.”196 Cities similarly contend, without citing to any legal
authority, that acquisition adjustments are not legally permitted as an addition to rate base for
ratemaking purposes or as a depreciable asset for regulatory ratemaking purposes.197 Staff disputes
ETI’s contention that the fact that the costs were approved as part of rate base in two previous ETI
dockets proves that they were reasonable, prudently incurred, and properly capitalized. Staff points
out that those two prior dockets were settled rate cases and, therefore, “provide no illumination on
this issue.”198 Finally, Staff argues that ETI failed to prove either element of the Commission’s two-
part Hooks test for the determination of whether the acquisition adjustment should be included in
rate base. Pursuant to the Hooks test, in determining whether an acquisition adjustment should be
included in rate base, “the Commission should consider whether or not the purchase price was
excessive and whether or not specific and offsetting benefits have accrued to ratepayers.”199
According to Staff, ETI’s acquisition adjustment should be disallowed because the Company failed
to meet it burden of proof on these two issues.200


           The ALJs are unpersuaded by the arguments of Staff and Cities. Their primary argument
(i.e., that acquisition adjustments are simply not allowed as an addition to rate base for ratemaking
purposes) is incorrect. Indeed, the Hooks decision, the precedent on which Staff relies for its
fallback argument, suggests that, more often than not, acquisition adjustments should be included in



195
      ETI Ex. 46 (Considine Rebuttal) at 5.
196
      Staff Ex. 1 (Givens Direct) at 35.
197
      Cities Initial Brief at 26.
198
      Staff Initial Brief at 11.
199
   Application of Hooks Telephone Company for a Rate Increase within Bowie County, Docket No. 2150,
Examiner’s Report at 2 (Mar. 28, 1980)(Hooks).
200
      Staff Reply Brief at 12.
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rate base: “Amortization of an acquisition adjustment need not be allowed as an expense in all
cases.”201


          Moreover, the evidence demonstrates that ETI met is burden under the Hooks test. As
discussed more fully in Section V.H. of this PFD, above, there is ample evidence in the record to
demonstrate that the Spindletop Facility is used and useful and provides specific and offsetting
benefits to ratepayers in a cost-effective manner. The evidence further shows that the acquisition
adjustment represents costs that were actually incurred by ETI in the furtherance of acquiring the
Spindletop Facility, and not a mere mark-up in original cost. For these reasons, the ALJs conclude
that the $1,127,778 incurred by ETI in internal acquisition costs associated with the purchase of the
Spindletop Facility was reasonable, necessary, and properly incurred. Accordingly, the ALJs agree
that it should be included in ETI’s rate base.


K.        Capitalized Incentive Compensation

          In the application, some of the incentive payments ETI made to its employees were
capitalized into plant in service accounts and ETI asks to include those amounts in rate base.202 A
portion of those capitalized accounts represents payments made by ETI for incentive compensation
tied to financial goals (financially-based incentive compensation). Cities contend that, consistent
with Commission precedent, ETI ought not be allowed to include in rate base the portion of its
capitalized incentive compensation that is attributable to financially-based incentive
compensation.203 The issue of whether financially-based incentive compensation is recoverable as a
portion of Operating Expenses is discussed at length in Section VII.D.2. of this PFD. ETI makes the
same arguments in favor of recoverability in that section that it makes here as to the inclusion of
financially-based incentive compensation in rate base. The discussion of that issue need not be
repeated here, but the analysis is the same. In summary, the ALJs conclude that ETI should not be
entitled to recover its financially-based incentive compensation costs. Thus, for the same reasons
discussed in Section VII.D.2, the ALJs agree with Cities’ contention that the portion of ETI’s


201
      Hooks (emphasis added).
202
      Cities Ex. 2 (Garrett Direct) at 52.
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incentive payments that are capitalized and that are financially-based should be excluded from ETI’s
rate base.


           On the other hand, the ALJs disagree with Cities as to the amount of that exclusion. Cities
argue that $9,835,111 (Cities’ estimate of ETI’s financially-based incentive payments that are
capitalized each year into plant in service) should be removed from rate base.204 Broadly speaking,
ETI has two categories of incentive compensation programs – annual incentive programs, and long-
term incentive programs. To arrive at the figure of $9,835,111, Cities’ witness Garrett assumed that:
(1) 100 percent of the costs of the long-term incentive programs were financially-based and,
therefore, should be excluded from rate base; and (2) his calculated percentage of the annual
incentive programs were financially-based and, therefore, should be excluded from rate base. He
then applied those percentages to the incentive costs that ETI capitalized in 2008, 2009, and the
portion of 2010 prior to the Test Year.205


           As explained in Section VII.D.2., the ALJs agree that Mr. Garrett was correct to recommend
removing 100 percent of the cost of ETI’s long-term incentive programs. However, as to the annual
incentive programs, he defined what qualifies as “financially based” much too broadly, and therefore
wrongly assumed that his calculated percentage of the costs of those programs should be excluded.
Instead, the ALJs conclude that the actual percentages should be used to determine the amount that
is financially based.206


           Finally, ETI challenges Mr. Garrett’s attempt to disallow capitalized incentive costs from
2008 through June 30, 2009.


           Much of the rate base that Mr. Garrett seeks to disallow (namely, costs from 2007
           through June 30, 2009) is not presented for review in this rate case. Rather those
           costs were presented for review in the Company’s last rate case, Docket No. 37744,

203
      Id. at 52-53.
204
      Id. at 52-53; Cities Initial Brief at 27.
205
      Cities Ex. 2 (Garrett Direct) at 53 and MG-2.10.
206
      See discussion in Section VII.D.2.
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          in which the Company presented capital additions for the period of April 1, 2007,
          through June 30, 2009. . . . Even though Docket No. 37744 was a settled case, the
          final order concluded that ‘[b]ased on the evidence in this docket, the overall total
          invested capital through the end of the test year meets the requirements in PURA §
          36.053(a) that electric utility rates be based on original cost, less depreciation of
          property used and useful to the utility in providing service.’ This conclusion goes
          beyond merely settling issues without deciding anything and should be construed as
          to be conclusive as to the reasonableness of capital costs at issue in that prior case.207

          The ALJs agree. The Test Year for ETI’s prior ratemaking proceeding ended on June 30,
2009. The reasonableness of ETI’s capital costs (including capitalized incentive compensation) was
dealt with by the Commission in that proceeding and is not at issue here. Thus, the ALJs conclude
that exclusion of capitalized incentive compensation that is financially-based can only be made for
incentive costs that ETI capitalized during the period from July 1, 2009 (the end of the prior Test
Year) through June 30, 2010 (the commencement of the current Test Year). The amount of the
exclusion is not specifically known at this time.


       VI.   RATE OF RETURN [Germane to Preliminary Order Issue Nos. 4 and 11]

A.        Capital Structure

          ETI’s capital structure is 50.08 percent debt and 49.92 percent equity. No party has taken
issue with ETI’s capital structure. Therefore, the ALJs recommend that the Commission enter an
order finding that the appropriate capital structure for ETI is 50.08 percent debt and 49.92 percent
equity.


B.        Return on Equity

          The United States Supreme Court has set forth a minimum constitutional standard governing
equity returns for utility investors:


          From the investor or company point of view it is important that there be enough
          revenue not only for operating expenses but also for the capital costs of the business.
          These include service on the debt and dividends on the stock. By that standard the

207
      ETI Initial Brief at 44, quoting Docket No. 37744, Order at CoL 10 (Dec. 13, 2010).
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        return to the equity owner should be commensurate with returns on investments in
        other enterprises having comparable risks. That return, moreover, should be
        sufficient to assure confidence in the financial integrity of the enterprise, so as to
        maintain its credit and to attract capital.208

Thus, a utility must have a reasonable opportunity to earn a return that is: (1) commensurate with
returns on equity investments in enterprises having comparable risks; (2) sufficient to ensure the
financial soundness of the utility’s operations; and (3) adequate to attract capital at reasonable rates,
thereby enabling it to provide safe, reliable service. The allowed ROE should enable the utility to
finance capital expenditures at reasonable rates and to maintain its financial flexibility during the
period in which the rates are expected to remain in effect.


        1. Proxy Group

        Because ETI is not a publicly traded company, it is necessary to establish a group of
companies that are publicly traded and that are comparable to ETI in certain fundamental business
and financial respects to serve as its “proxy” in the ROE estimation process. Both financial theory
and legal precedent support the use of comparable companies within a proxy group to determine a
utility’s ROE, and all of the ROE witnesses in this case have relied on proxy groups to estimate a
required ROE for ETI.


        ETI witness Hadaway started with all the vertically integrated electric utilities that are
included in the Value Line Investment Survey (Value Line). To improve the group’s comparability
with ETI, which has a senior secured bond ratings of BBB+ (Outlook Negative) from Standard &




208
    Federal Power Comm’n v. Hope Natural Gas Co., 320 U.S. 591, 603, 64 S. Ct. 281, 288 (1944); see also
Bluefield Waterworks & Improvement Co. v. Public Serv. Comm’n of W. Va., 262 U.S. 679, 692-93, 43 S. Ct.
675, 679 (1923) (“A public utility is entitled to such rates as will permit it to earn a return on the value of the
property which it employs for the convenience of the public equal to that generally being made at the same
time and in the same general part of the country on investments in other business undertakings which are
attended by corresponding risks and uncertainties; but it has no constitutional right to profits such as are
realized or anticipated in highly profitable enterprises or speculative ventures. The return should be
reasonably sufficient to assure confidence in the financial soundness of the utility and should be adequate,
under efficient and economical management, to maintain and support its credit and enable it to raise the
money necessary for the proper discharge of its public duties.”).
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Poor’s (S&P) and Baa2 (stable) rating from Moody’s Investors Service (Moody’s), Dr. Hadaway
imposed the following restrictions:


x   comparable companies had to have senior secured bond ratings of at least BBB by S&P or Baa
    by Moody’s;

x   comparable companies had to derive at least 70 percent of revenues from regulated utility sales;

x   comparable companies had to have consistent financial records not affected by recent mergers or
    restructuring; and

x   comparable companies had to have a consistent dividend record with no dividend cuts or
    resumptions during the past two years.

Those selection criteria resulted in a 23-utility proxy group.


        State Agencies witness Miravete excluded Entergy from his proxy group, but otherwise his
proxy group was identical to ETI’s. Cities witness Parcell ran his calculations using both
Dr. Hadaway’s 23-utility proxy group and another 8-utility proxy group, but they produced similar
ROE results. TIEC witness Gorman used the same 23 utility proxy group as ETI witness Hadaway
used.


        Staff witness Cutter was the only witness to use a different proxy group. He used a 13 utility
proxy group for his discounted cash-flow (DCF) analysis. To arrive at this proxy group, Mr. Cutter
started with all of the domestic electric-utility companies tracked by Value Line because Value Line
is the most widely used, independent investment service in the world. Then he eliminated the
utilities that did not meet the following criteria:


x   Value Line Financial Strength ratings of A+, A or B++;

x   A capital structure including less than 45 percent, or more than 55 percent, debt;

x   Total capitalization in excess of five billion dollars;

x   No recent dividend cuts or omissions;
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x   No recent or potential merger activities or other major capital expansion; and

x   No Value Line appraisal of being outside the norm.

On his final analysis, Mr. Cutter eliminated three of his 13 utility proxy group, referring to those he
eliminated as “outliers.” ETI points out, however, that one of the remaining ten companies, Con
Ed, is not comparable to ETI because it is a delivery company as opposed to a vertically integrated
utility. ETI’s essential criticism of Mr. Cutter’s proxy group analysis is that he should have used a
larger proxy group and that he admitted a better comparison to ETI could be obtained from using a
larger proxy group.


       2. DCF Analysis

       To analyze ETI’s cost of equity capital, all of the testifying experts first performed a DCF
analysis. The DCF approach is based on the theory that a stock’s current price represents the present
value of all expected future cash flows. In its most general form, the DCF model is expressed as
follows:




Where P0 represents the current stock price, D1 . . . . D∞ are all expected future dividends, and k is
the expected discount rate, or required ROE. That equation can be simplified and rearranged to
ascertain the required ROE:




Where P0 represents the current stock price, D is expected future dividends, g is the growth rate, and
k is the expected discount rate, or required ROE.


       This is commonly referred to as the “Constant Growth DCF” model in which the first term is
the expected dividend yield and the second term is the expected long-term growth rate. The
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Constant Growth DCF model requires assumptions of: (1) a constant growth rate for earnings and
dividends; (2) a stable dividend payout ratio; (3) a constant price-to-earnings multiple; and (4) a
discount rate greater than the expected growth rate.


          ETI witness Hadaway’s DCF analysis was based on three versions of the DCF model. In the
first version of the DCF model, he used the constant growth format with long-term expected growth
based on analysts’ estimates of five-year utility earnings growth. In the second version of the DCF
model, for the estimated growth rate, Dr. Hadaway used only the long-term estimated gross domestic
product (GDP) growth rate. In the third version of the DCF model, Dr. Hadaway used a two-stage
growth approach, with stage one based on Value Line’s three-to-five-year dividend projections and
stage two based on long-term projected growth in GDP. The dividend yields in all three of the
annual models are from Value Line’s projections of dividends for the coming year and stock prices
are from the three-month average for the months that correspond to the Value Line editions from
which the underlying financial data are taken.209


          The DCF results for Dr. Hadaway’s comparable company group using the traditional
constant growth model indicated an ROE of 9.90 percent to 10.00 percent. Dr. Hadaway then
recalculated the constant growth results with the growth rate based on long-term forecasted growth
in GDP. With the GDP growth rate, the constant growth model indicates an ROE range of
10.40 percent to 10.70 percent. Although the GDP growth rate is higher than the average of
analysts’ growth rates, Dr. Hadaway testified that his GDP estimate is within the analysts’ range and
slightly below the 6.00 percent 3-to-5 year average growth rate projection from Value Line. Finally,
Dr. Hadaway’s multistage DCF model indicated an ROE range of 10.20 percent to 10.30 percent.
The results from the DCF model, therefore, indicate an ROE range of 9.90 percent to
10.70 percent.210 In his rebuttal, Dr. Hadaway updated his ROE analysis using current market
conditions but employing the same methodologies that he used in his previous analysis. After




209
      ETI Ex. 6 (Hadaway Direct) at 33-44.
210
      Id. at 44, Exhibit SCH-4.
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making adjustments to the proxy group to stay consistent with his selection criteria, Dr. Hadaway’s
indicated DCF range was 10.00 percent to 10.20 percent.211


           The principal argument against Dr. Hadaway’s analyses is that he used unsupported and
excessive growth rates. According to the intervenors, these excessive growth rates exaggerate future
cash flows, which results in an inflated ROE.


           Intervenors argue that Dr. Hadaway’s Analysts’ Constant Growth DCF model produces
excessive return estimates.212 In rebuttal, Dr. Hadaway’s analysts’ growth model produced a
10.1 percent group average ROE and a 10.0 percent group median ROE.213 The intervenors contend
that the group average long-term growth rate on which his DCF study was based was 5.62 percent,
which is far too high to be sustainable in the long-term (as required as an input in the Constant
Growth DCF model).214 According to intervenors, the excessive level of his growth rate is apparent
by comparison to current analysts’ projected growth for U.S. GDP, which range from 4.5 percent to
5.0 percent.215 Dr. Hadaway’s growth rate is more than 60 basis points above the most generous
expected growth of the U.S. economy. Intervenors contend that that nominal GDP should be the
ceiling of a reliable proxy for a utility dividend growth rate. Because the evidence shows that
nominal GDP as projected by consensus analysts, the Executive Branch, and the Congressional
Budget Office is 5 percent, Dr. Hadaway’s 5.62 percent growth rate is excessive and undermines the
reasonableness of his models.


           Intervenors criticize Dr. Hadaway’s decision on rebuttal to exclude Edison International in
his proxy group.216 Dr. Hadaway did so because Edison International’s ROE of 5.2 percent was
below a 5.07 percent cost of debt based on an average of Triple B utility rates for the time period

211
      Id. at 44.
212
      TIEC Ex. 2 (Gorman Direct) at 39.
213
      ETI Ex. 52 (Hadaway Rebuttal) at Ex. SCH-R-6.
214
   Id. at Ex. SCH-R-6; TIEC Ex. 2 (Gorman Direct) at 39; Cities Ex. 3 (Parcell Direct) at 36-37; OPC Ex. 1
(Szerszen Direct) at 23-24.
215
      TIEC Ex. 2 (Gorman Direct) at 19; Cities Ex. 3 (Parcell Direct) at 37.
216
      ETI Ex. 51 (Hadaway Rebuttal) at Ex. SCH-R-6.
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January 12-March 12, plus 100 basis points.217 Intervenors contend that this rationale is tenuous,
and that had Dr. Hadaway included Edison International (or even excluded Hawaiian Electric, the
utility in his proxy group that had the highest ROE) his own analysis (even with its excessive growth
rates) would have resulted in a 9.85 percent average ROE.


            Finally, Dr. Hadaway conceded that he used the same methodology for calculating GDP in
this case as he did in the Oncor rate case.218 Intervenors contend that Dr. Hadaway’s GDP
projections are not credible proxies for investor’s expected dividend growth rates because they are
not based on published analysts’ or government GDP forecasts. Rather, Dr. Hadaway forecasts
future GDP growth using his own personal calculation that forecasts GDP by examining historic
GDP growth over the last 10, 20, 30, 40, 50, and 60-year periods and weighting those averages.219
Intervenors note that this approach was rejected by the Commission in the Oncor rate case.220


            Staff witness Cutter used the DCF model to project ETI’s cost of equity. Under Mr. Cutter’s
view, the theory underlying the DCF model is that the price of a share is equal to the present value
of all future earnings. Unless the stock is sold for a profit (or loss) from the price it was originally
purchased, the only way to determine earnings on a share is to determine its future dividends. This
requires, in Mr. Cutter’s opinion, an understanding of investors’ current expectations of growth of
those dividends. The issue is the growth expectation that investors have embodied in the current
price of the stock. According to Mr. Cutter, the best way to arrive at a reliable growth estimate of
those dividends is to use the growth estimates of investment advisory firms rather than the estimates
of a single, independent analyst.221


            Mr. Cutter used both Value Line and Zacks Investment Service (Zacks) in ascertaining
long-term earnings growth rates. He used Value Line because it is the most widely used

217
      Id.
218
      Tr. at 227-228.
219
      ETI Ex. 6 (Hadaway Direct) at Ex. SCH-3; Tr. at 218.
220
  Application of Oncor Electric Delivery Company, LLC, for Authority to Change Rates, Docket No. 35717,
PFD at 72-73.
221
      Staff Ex. 6 (Cutter Direct) at 10-15.
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independent investment service in the world and Zacks because it compiles consensus earnings
forecasts from groups of professional security analysts.222


          Mr. Cutter’s DCF analysis resulted in range from 7.46 percent to 10.71 percent, with a point
estimate for cost of equity being 9.3 percent.


          TIEC witness Gorman’s first DCF model was a constant growth model using consensus
analysts’ growth rates that resulted in an average constant growth DCF of 9.32 percent and a median
constant growth DCF of 9.84 percent. The average analysts’ growth rate was 4.94 percent.223
According to TIEC, ETI does not claim that a constant growth model using analysts’ growth rates is
inappropriate and argues that Dr. Hadaway failed to offer any rebuttal testimony criticizing
Mr. Gorman’s Analysts’ Growth DCF model.


          Mr. Gorman also performed a constant growth DCF model using sustainable growth rates.
His average sustainable growth rate for the proxy group was 4.54 percent and produced a proxy
group average and median DCF result of 8.91 percent and 8.9 percent, respectively.224 According to
TIEC, a sustainable growth rate is based on the percentage of a utility’s earnings that are retained
and reinvested in utility plant and equipment.225


          Mr. Gorman also performed a multi-stage DCF model to reflect changing growth
expectations that would reflect the possibility of non-constant growth for a company over time.
Mr. Gorman’s multi-stage model reflected three growth periods: (1) a short-term growth period of
five years; (2) a transition period for years six through ten; and (3) a long-term growth period,
starting in year 11 through perpetuity. For the short-term period, Mr. Gorman relied on the
consensus analysts’ growth projections from his constant growth DCF model (i.e., 4.94 percent).
For the second stage (i.e., the transition period), growth rates are reduced or increased by an equal


222
      Staff Ex. 6 (Cutter Direct) at 13.
223
      TIEC Ex. 2 (Gorman Direct) at Ex. MPG-4.
224
      TIEC Ex. 2 (Gorman Direct) at 18.
225
      TIEC Ex. 2 (Gorman Direct) at 17.
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factor, which reflect the difference between the analysts’ growth rates and the GDP growth rate. For
the long-term period, he assumed the maximum sustainable growth rate for a utility company as
proxied by the consensus analysts’ projected growth rate for the U.S. GDP (i.e., 5.0 percent). The
result of his multi-stage growth DCF model was an average ROE of 9.37 percent and a median of
9.48 percent.226


            Cities witness Parcell calculated the DCF results for each company in his proxy group by
using and considering five indicators of growth expectations consisting of: (i) 2007 – 2011 earnings
retention; (ii) five-year historical average earnings per share, dividends per share, and book value per
share; (iii) projected earnings retention; (iv) projected EPS, DPS, BVPS; and (v) projected EPS as
reported by Yahoo Finance. Using this in his DCF model resulted in an ROE of 9.0 percent to
9.5 percent.227


            OPC witness Szerszen’s DCF analysis used the same group of 23 comparable companies
included in Dr. Hadaway’s DCF analysis.                Dr. Szerszen’s DCF analysis was framed with
consideration of ETI’s financial integrity as discussed by the major bond rating agencies, the current
and projected interest rate environment, and investment analyst views of the regulated utility
sector.228 Interest rates are currently very low, as reflected in the yields to maturity and interest rates
on various fixed income investments. OPC contends, in contrast to Dr. Hadaway, that utility stocks
have been less volatile than the stock market in general.229 This is confirmed by Value Line’s
December 23, 2011, observation that “electric utility stocks have long been viewed as a safe haven
in volatile markets, due in large part to their generous dividend yields.”230 Dr. Szerszen also took
exception to Moody’s characterization of ETI as having above average business and regulatory risk.
Moody’s assessment is primarily based on the lack of pass-through regulatory lag-reducing cost
recovery mechanisms in Texas compared to Entergy’s Louisiana and Mississippi jurisdictions. Dr.


226
      TIEC Ex. 2 (Gorman Direct) at 19, Ex. MPG-9.
227
      Cities Ex. 3 (Parcell Direct) at 24, 33.
228
      OPC Ex. 1 (Szerszen Direct) at 8-17.
229
      Id. at 15.
230
      Id.
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Szerszen testified that ETI may not have a formula rate plan similar to the Louisiana and Mississippi
Entergy operating companies, but it does have a Distribution Cost Recovery Factor (DCRF) and
Transmission Cost Recovery Factor (TCRF) available that “will allow ETI to charge ratepayers for
additional distribution and transmission investments outside of a traditional rate request filing.”231
None of Entergy’s other operating companies have TCRF and DCRF riders. OPC notes that Cities
witness Parcell agrees that the availability of such recovery mechanisms affects ETI’s level of risk;
he testified that a combination of ETI’s fuel factor rider, TTC rider, energy efficiency rider,
hurricane cost recovery rider, rate case expense rider, proposed increased customer service charge,
and DCRF and TCRF riders results in about 30 percent of ETI’s total overall requested revenue
requirement being subject to revenue risk and regulatory lag.232


          Dr. Szerszen incorporated two different dividend yield calculations in her DCF model. The
first calculation estimated a dividend yield using 2011 average stock prices and 2012 projected
dividend rates for each company, and the second calculation incorporated more recent March 5,
2012, closing prices for the comparables. The average dividend yield using 2011 average stock
prices was 4.66 percent and, using March 5, 2012, closing prices, was 4.32 percent.233


          Dr. Szerszen provided some practical examples of how blind reliance on analyst earnings
growth projections can lead to questionable DCF growth rates. At least five of the comparable
utility companies had five-year earnings growth rate projections that ranged from 8.5 percent to
11 percent. Dr. Szerszen stated that she was unaware of any regulated utility company that has
consistently achieved such high earnings growth rate over the past 28 years, and that it is reasonable
to assume such performance is unlikely in the longer term future. Dr. Szerszen’s review of the
comparable company past and projected growth rates resulted in a reasonable dividend growth rate
expectation of 3.9 percent to 5 percent. Depending on whether 2011 average stock prices are used or




231
      Id at 11-13.
232
      Cities Ex. 3 (Parcell Direct) at 16-18.
233
      OPC Ex. 1 (Szerszen Direct) at 17.
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the updated 2012 stock prices are used, Dr. Szerszen’s DCF analysis resulted in an ROE ranging
from 8.32 percent to 9.32 percent.234


           State Agencies’ witness Miravete’s DCF analysis used calculations for three averaging
periods, 30, 90 (the reference period), and 180 days ending on March 2, 2012, respectively. For the
commonly used 90 day averaging period, the capitalization-weighted average ROE is 9.23 percent.
Evaluating the averaging period at either 30 or 180 days produces ROE estimates of 9.24 percent
and 9.34 percent, respectively. Dr. Miravete weighed the computations by the capitalization of each
firm to correct the effect of each variable according to the relative market value of the corresponding
utility. According to Dr. Miravete, this approach avoids the distortion caused by adding numerous,
but possibly irrelevant, firms that may produce biased estimates. Dr. Miravete conceded that the
effect of ignoring differences in scale of utilities in the determination of the ROE is substantial. He
acknowledged that if he had ignored the differences in size of these electric utilities, his DCF ROE
estimate would have been 9.68 percent.235


           3. Risk Premium Analysis

           Dr. Hadaway’s risk premium studies are divided into two parts. First, he compared electric
utility authorized ROEs for the period 1980-2010 to contemporaneous long-term utility interest
rates. The differences between the average authorized ROEs and the average interest rate for the
year is the indicated equity risk premium. He then added the indicated equity risk premium to the
forecasted and current triple-B utility bond interest rate to estimate ROE.236


           In calculating the equity risk premium, Dr. Hadaway adjusted for the inverse relationship
between equity risk premiums and interest rates (when interest rates are high, risk premiums are low
and vice versa). Dr. Hadaway provided regression analyses of the allowed annual equity risk
premiums relative to interest rate levels. The negative regression coefficients confirm the inverse
relationship between equity risk premiums and interest rates according to ETI. Dr. Hadaway used

234
      Id. at 22.
235
      State Agencies Ex. 1 (Miravete Direct) at 12-13.
236
      ETI Ex. 6 (Hadaway Direct) at 36-38, 45.
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that negative interest rate change coefficient in conjunction with current and forecasted interest rates
to establish the appropriate ROE.237 Staff witness Cutter agreed that the risk premium analysis
needs to reflect this adjustment.238


           The results of Dr. Hadaway’s initial equity risk premium studies indicate an ROE range of
10.00 percent to 10.01 percent. ETI states that these results reflect the sharp drop in interest rates
that have occurred for high quality borrowers. The Federal Reserve System’s continuing “easy
money” policies have provided renewed liquidity in the credit markets that is reflected in these
lower yields. These models, however, cannot capture the current equity volatility or the increased
level of risk aversion for equity investors. These circumstances indicate that the cost of equity has
not declined to the extent that interest rates on utility debt have dropped. Thus, Dr. Hadaway
testified that the results of the risk premium analysis must be discounted and more emphasis placed
on the DCF analysis.239


           In his rebuttal, Dr. Hadaway updated his ROE analysis using current market conditions but
employing the same methodologies that he used in his previous analysis.240 His updated risk
premium analysis was an ROE of 10.38 percent using projected triple-B utility interest rates and
9.96 percent using current triple-B utility interest rates.241


           TIEC contends that Dr. Hadaway’s utility risk premium analysis is flawed for two primary
reasons. First, Dr. Hadaway developed a forward-looking risk premium model that relied on
forecasted interest rates and volatile utility spreads that are uncertain and produce inaccurate results.
As Mr. Gorman testified, it is more reasonable at this time to rely on current observable interest
rates rather than forecasted projections. Over the last several years, forecasted yield projections
have proven to be overstated because, even though interest rates have been projected to increase,


237
      ETI Ex. 6 (Hadaway Direct) at 45-46, Ex. SCH-5; ETI Ex. 52 (Hadaway Rebuttal) at 32.
238
      Staff Ex. 6 (Cutter Direct) at 20.
239
      ETI Ex. 6 (Hadaway Direct) at 10-23, 45; Tr. at 233-235.
240
      ETI Ex. 52 (Hadaway Rebuttal) at 44.
241
      Id. at 45.
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those projections have consistently been proven wrong.242 Accordingly, Dr. Hadaway’s forecasted
utility bond yield of 5.17 percent is overstated.


          Second, TIEC argues that Dr. Hadaway’s risk premium model is flawed because he
improperly inflates his actual risk premium of 3.28 percent with an adjustment of 1.56 percent that
he asserts reflects the inverse relationship between interest rates and utility risk premiums.243 TIEC
argues that Dr. Hadaway’s use of this adjustment is improper and not supported by academic
research. Mr. Gorman testified that “a relative investment risk differential cannot be measured
simply by observing nominal interest rates.”244 He noted:


          While academic studies have shown that, in the past, there has been an inverse
          relationship with these variables, researchers have found that the relationship
          changes over time and is influenced by changes in perception of the risk of bond
          investments relative to equity investments, and not simply changes to interest
          rates.245

          As described in Mr. Gorman’s testimony, correcting Dr. Hadaway’s models for the
elimination of this inverse relationship adjustment puts Dr. Hadaway’s risk premium in the range of
8.5 percent to 10 percent, with a midpoint of 9.3 percent.246


          Staff witness Cutter’s “conventional risk premium estimate” estimated the cost of ETI’s
equity by comparing the costs of equity authorized for utilities across the United States to the yields
of large-company corporate bonds that are rated Baa by Moody’s within the timeframe of 1980
through 2011. This risk premium approach relies on the historical relationship between two indices




242
      TIEC Ex. 2 (Gorman Direct) at 42-43; OPC Ex. 1(Szerszen Direct) at 27-28.
243
      TIEC Ex. 2 (Gorman Direct) at 42-43; see also ETI Ex. 6 (Hadaway Direct) at Ex. SCH-5 at 1.
244
      TIEC Ex. 2 (Gorman Direct) at 44.
245
    TIEC Ex. 2 (Gorman Direct) at 44 (citing “The Market Risk Premium: Expectational Estimates Using
Analysts’ Forecasts,” Robert S. Harris and Felicia C. Marston, Journal of Applied Finance, Volume 11, No.
1, 2001 and “The Risk Premium Approach to Measuring a Utility’s Cost of Equity,” Eugene F. Brigham,
Dilip K. Shome, and Steve R. Vinson, Financial Management, Spring 1985).
246
      TIEC Ex. 2 (Gorman Direct) at 45.
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to forecast a value for one of the indices in a period for which it is unknown by using the known
value of the other one during that same period.247


          To account for the relationship between the authorized costs of equity and the bond yields
required to quantify ETI’s cost of equity, Mr. Cutter subtracted the bond yields from the authorized
costs of equity to determine a risk premium for the riskier equity. He tested the data by performing a
regression analysis, which showed with high confidence that there is a trend in the relationship. It is
an inverse trend, in which the risk premiums increase as bond yields decrease. On average, from
1980 to 2011, risk premiums increased 0.4207 percent for every 1.00 percent that bond yields
decreased.248


          The calculation of the adjustment to the risk premium that the regression analysis indicated
was incorporated in Staff’s analysis. The results of this risk premium analysis produced a cost of
equity of 9.81 percent.249


          Mr. Gorman’s risk premium analysis produced an ROE estimate in the range of 9.2 percent
to 9.4 percent, with a midpoint estimate of approximately 9.3 percent. His risk premium model was
based on two estimates of an equity risk premium. First, he estimated the difference between the
required return on utility common equity investments and U.S. Treasury bonds for the period 1986
through 2011, which produced an equity risk premium of 5.23 percent. The second equity risk
premium estimate was based on the difference between regulatory commission-authorized returns on
common equity and contemporary “A” rated utility bond yields for the period 1986 through 2011,
which produced an equity risk premium of 3.8 percent. Mr. Gorman testified that “[t]he equity risk
premium should reflect the relative market perception of risk in the utility industry today.”250




247
      Staff Ex. 6 (Cutter Direct) at 10, 19.
248
      Staff Ex. 6 (Cutter Direct) at 20.
249
      Id. at 20, Attachment SC-6.
250
      TIEC Ex. 2 Gorman Direct) at 26.
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Accordingly, to gauge investor expectations he examined the yield spread between utility bonds and
Treasury bonds over the last 32 years.251


           According to TIEC, this analysis showed that the current utility bond yield spreads over
Treasury bond yields are lower than the 32-year average spreads, which is evidence that “the market
considers the utility industry to be a relatively low risk investment and demonstrates that utilities
continue to have strong access to capital.”252 Mr. Gorman then added a projected long-term
Treasury bond yield to his estimated equity risk premium over Treasury yields, which produced a
common equity in the range of 8.2 percent to 9.95 percent. Due to unusually large yield spreads
between Treasury bond and “Baa” utility bond yields, Mr. Gorman gave two-thirds weight to his
high end risk premium of 9.95 percent and one-third weight to his low-end risk premium of
8.2 percent, which produced an equity risk premium of 9.4 percent. He also added his equity risk
premium over utility bond yields to the current 13-week average yield on “Baa” rated utility bonds
for the period ending March 2, 2012, of 5.05 percent. Adding his equity risk premium of
3.03 percent to 4.62 percent to the bond yield of 5.05 percent, produced an ROE in the range of
8.08 percent to 9.67 percent, which he then weighted more heavily on the high end estimate to
produce a recommendation of 9.2 percent.253


           The primary criticism that Dr. Hadaway lodged against Mr. Gorman’s risk premium analysis
was that Mr. Gorman did not adjust his analysis upward to reflect a purported inverse relationship
between equity risk premiums and interest rates.254 For example, Dr. Hadaway’s risk premium
analysis adjusted his risk premium results by 1.56 percent to account for this relationship.255


           OPC witness Szerszen also performed a risk premium analysis, using Dr. Hadaway’s study
of historical authorized electric company allowed returns on equity and average bond yields. The


251
      Id. at 25-28.
252
      Id. at 27.
253
      TIEC Ex. 2 (Gorman Direct) at 26-28.
254
      ETI Ex. 52 (Hadaway Rebuttal) at 32.
255
      ETI Ex. 6 (Hadaway Direct) at Ex. SCH-5.
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average risk premium from Dr. Hadaway’s 1980-2010 study was 328 basis points.256 Adding this
historical risk premium to current triple B bond yield (4.67 percent) results in a 7.95 percent
risk-premium derived DCF rate, and using Dr. Hadaway’s 5.17 percent projected bond yield results
in a risk premium derived rate of 8.45 percent. Giving more weight to the 2001-2010 risk premiums
shown in Dr. Hadaway’s exhibit results in an average risk premium of 4.21 percent. This yields an
8.88 percent to 9.38 percent risk premium derived cost of equity based on the current 4.67 percent
and projected 5.17 percent bond yields, according to Dr. Szerszen’s analysis.257


           4. Comparable Earnings

           Cities witness Parcell also performed a Comparable Earnings analysis. According to
Mr. Parcell, the Comparable Earnings method is derived from the “corresponding risk” standard of
the Bluefield and Hope cases. This method is thus based upon the economic concept of opportunity
cost. The cost of capital is an opportunity cost: the prospective return available to investors from
alternative investments of similar risk.258


           The Comparable Earnings method is designed to measure the returns expected to be earned
on the original cost book value of similar risk enterprises. Thus, according to Mr. Parcell, this
method provides a direct measure of the fair return, because the Comparable Earnings method
translates into practice the competitive principle upon which regulation is based.259


           The Comparable Earnings method normally examines the experienced and/or projected
returns on book common equity. The logic for examining returns on book equity follows from the
use of original-cost, rate-base regulation for public utilities, which uses a utility’s book common
equity to determine the cost of capital. This cost of capital is, in turn, used as the fair rate of return
which is then applied (multiplied) to the book value of rate base to establish the dollar level of



256
      ETI Ex. No. 6 (Hadaway Direct) at Ex. SCH-5.
257
      OPC Ex. 1 (Szerszen Direct) at 29-30.
258
      Cities Ex. 3 (Parcell Direct) at 28.
259
      Id. at 29.
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capital costs to be recovered by the utility. Mr. Parcell stated that this technique is thus consistent
with the rate base methodology used to set utility rates.260


            Mr. Parcell conducted the Comparable Earnings methodology by examining realized returns
on equity for several groups of companies and evaluating the investor acceptance of these returns by
reference to the resulting market-to-book ratios. He testified that in this manner it is possible to
assess the degree to which a given level of return equates to the cost of capital.


            Mr. Parcell’s Comparable Earnings analysis is based on market data (through the use of
market-to-book ratios) and is thus essentially a market test. As a result, he testified that his analysis
is not subject to the criticisms occasionally made by some who maintain that past earned returns do
not represent the cost of capital. In addition, he stated that his analysis uses prospective returns and
thus is not confined to historical data.261


            Mr. Parcell’s Comparable Earnings analysis considered the experienced equity returns of the
proxy groups of utilities for the period 1992-2011 (i.e., the last twenty years). His Comparable
Earnings analysis required an examination of a relatively long period of time to determine trends in
earnings over at least a full business cycle. Further, in estimating a fair level of return for a future
period, it is important to examine earnings over a diverse period of time to avoid any undue
influence from unusual conditions that may occur in a single year or shorter period. Therefore, in
forming his judgment of the current cost of equity he focused on two periods: 2002-2011 (the recent
business cycle) and 1992-2001 (the prior business cycle).262


            Based on the recent earnings and market-to-book ratios, Mr. Parcell’s Comparable Earnings
analysis indicated that the cost of equity for the proxy utilities is no more than 9.5 percent to
10.0 percent (9.75 percent mid-point). Recent returns of 10.0 percent to 12.1 percent have resulted
in market-to-book ratios of 143 and greater. Prospective returns of 9.5 percent to 10.3 percent result


260
      Id.
261
      Cities Ex. 3 (Parcell Direct) at 29.
262
      Id. at 30.
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in anticipated market-to-book ratios of over 125. As a result, it is apparent that returns below this
level would result in market-to-book ratios of well above 100. According to Mr. Parcell, an ROE of
9.5 percent to 10.0 percent should thus result in a market-to-book ratio of well over 100 .263


          5. CAPM Analysis

          The Capital Asset Pricing Model (CAPM) is a risk premium approach that estimates the
ROE for a given security as a function of a risk-free return plus a risk premium to compensate
investors for the non-diversifiable, or systematic, risk of that security. The CAPM formula is as
follows:


                                                   Ke = rf + β(rm – rf)

Where Ke equals the required market ROE; β equals the Beta of an individual security; rf equals the
risk free rate of return; and rm equals the required return on the market as a whole. In this equation,
(rm – rf) represents the market risk premium. According to the theory underlying the CAPM,
because diversifiable risk can be diversified away, investors should be concerned only with
non-diversifiable risk, which is measured by Beta. In effect, Beta represents the risk of the particular
security relative to the market as a whole.


          Only Staff witness Cutter, Cities witness Parcell, and State Agencies witness Miravete used
the CAPM methodology to estimate ETI’s ROE.


          Mr. Cutter used CAPM in the qualitative analysis of ETI’s cost of equity. He did not directly
use the CAPM in the determination of ETI’s cost of equity because it yielded a cost of equity that
was over 200 basis points lower than the lower of the other two estimates, while those other two
estimates were less than half a percent apart from each other.264 The CAPM provides an additional
indication that a significant drop to the estimated costs of equity that Staff made in prior dockets is




263
      Cities Ex. 3 (Parcell Direct) at 31-32.
264
      Staff Ex. 6 (Cutter Direct) at 21.
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appropriate because the CAPM estimate is lower than either of the two other approaches even when
adjusted for the current low yield on Treasury Bonds.265


            Mr. Cutter testified that the CAPM is one of the cornerstones of financial theory.266 In its
simplest sense, the model describes the relationship between the risk of an asset and its expected
return, and assumes that investors will not hold a risky asset unless they are adequately compensated
for the risk.267


            In this case, without any adjustment to the way it has been used in recent rate cases at the
Commission, the CAPM yielded a cost of equity for ETI of 6.93 percent. Mr. Cutter testified that
aspects of the capital markets today were likely causing the CAPM’s cost of equity estimate to be
low. Specifically, the Federal Reserve System is following an aggressive policy designed to keep
the yields of both short-term and long-term Treasury bonds low. This policy influences two of the
three variables used in the CAPM formula to be lower, which, in turn, makes the CAPM’s final
estimate of ETI’s cost of equity lower.268


            To account for the impact of this aggressive Federal Reserve System policy, Mr. Cutter made
two adjustments to his CAPM analysis. First, Mr. Cutter adjusted the risk-free rate variable in the
CAPM because it is most influenced by current Federal Reserve System policy. By changing this
variable to 3.7 percent (which is the average yield from 1926 through 2010 of the risk-free rate’s
proxy security, U.S. Treasury Bills), the CAPM’s estimate of ETI’s cost of equity increased from
6.93 percent to 7.92 percent, or by 99 basis points.269


            The second adjustment to the CAPM result that Mr. Cutter made to account for the current
aggressive Federal Reserve System policy was to the risk premium, which is also particularly
sensitive to Federal Reserve System policy. By using the difference between the averages of the

265
      Id.
266
      Id.
267
      Id.
268
      Staff Ex. 6 (Cutter Direct) at 21-24.
269
      Id. at 24.
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yield of long-term government bonds and the yield of large company stocks between 1926 and 2010,
the effect of Federal Reserve System policy on the risk premium was significantly diluted.
Mr. Cutter found that because the CAPM estimate of ETI’s cost of equity was excessively low, even
with adjustments for Federal Reserve System policy, it would be appropriate to further adjust it by
multiplying the unadjusted estimate plus two times the effect of adjusting the risk-free rate, or:
6.93 percent + (2 * 0.99 percent) = 8.91 percent.270 It is important to note, however, that Mr. Cutter
used the CAPM analysis only as a qualitative check on its DCF and risk premium analyses, not as an
independent source of analysis.


          Although Cities witness Parcell did perform a CAPM analysis, he does not employ the
CAPM results in arriving at his 9.0 percent to 10.0 percent range of results.271


          State Agencies witness Miravete used the daily average of the yield of the ten-year Treasury
bond between December 1, 2011, and March 2, 2012, as reported by the Board of Governors of the
Federal Reserve System, as his risk-free return in his CAPM model. He used Value Line’s most
recent betas for the regulated utilities included in the proxy group. Dr. Miravete corrected the betas
by substituting an average between their value and 1.0 to recognize that markets trend towards
long-term equilibrium because these regulated utilities were able to attract investors during the most
troubled times, which indicates that the perceived market risk of these utilities is lower than for other
firms. Dr. Miravete’s capitalization-weighted average CAPM ROE is 7.64 percent on a 90 days
averaging period, with a range between 7.64 percent (30 days) and 8.28 percent (180 days).
Dr. Miravete characterizes these estimates as low relative to those of the DCF model because of the
low yields of Treasury bonds after the implementation of the quantitative easing monetary policy
over the past two years.272




270
      Id. at 21, 24-25.
271
      Cities Ex. 3 (Parcell Direct) at 3, 25-28.
272
      State Agencies Ex. 1 (Miravete Direct) at 19-21.
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       6. ALJs’ Analysis

       Given the detail, time, and effort that went into the various experts’ testimony on this issue,
one might easily conclude that the development of an estimated ROE is a precise science. But, as
acknowledged by virtually all experts on the subject, estimating the cost of equity is not an exact
science but rather a result of informed judgment.


       The first question that must be addressed is the appropriate proxy group. There were
essentially only two competing views on this issue – one presented by Dr. Hadaway and the other by
Mr. Cutter. The ALJs have reviewed the evidence and the arguments of both sides with respect to
the composition of the proxy group. Although Staff’s proxy group could, in some respects, be
considered more comparable to ETI than Dr. Hadaway’s larger group, the ALJs do not believe that
this overcomes the flaws inherent in such a small group. In the end, a group of nine companies,
while comparable, simply does not provide a robust enough sample to create a valid group for
comparison. The ALJs therefore find that the 23 utility group selected by ETI witness Hadaway is
the appropriate proxy group.


       The next issue is the core issue to be decided: the appropriate ROE for ETI. The experts in
this case testified to the following ROE ranges or estimates, depending on the calculation
methodology employed:


           Witness/Analysis                    Range          Ultimate Recommendation
      Hadaway - DCF                       9.9 – 10.7                    10.6
      Hadaway – Risk Premium              9.96 – 10.38

      Cutter – DCF                        7.46 – 10.71                      9.6
      Cutter – Risk Premium               9.81
      Cutter – CAPM                       8.91

      Gorman –DCF                         9.3 – 9.7                         9.5
      Gorman – Risk Premium               9.2 – 9.4

      Parcell – DCF                       9.0 – 9.5                         9.5
      Parcell – Comparable Earnings       9.5 – 10.0
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               Witness/Analysis                   Range       Ultimate Recommendation
         Szerszen – DCF                       8.32 – 9.32                9.3
         Szerszen – Risk Premium              9.3

         Miravete – DCF                       9.23 – 9.34                  9.3
         Miravete – CAPM                      7.64 – 8.28

Just focusing on the ultimate ROE recommendations, it is clear that there is a fairly tightly grouped
range when considering Staff and the intervenors. This ranges from a low of 9.3 percent to a high of
9.6 percent. The range expands when it is considered that Staff witness Cutter did not contest ETI’s
assertion that Staff’s DCF recommended ROE would be 10.0 percent if he had used the same proxy
group as the other witnesses.273 The ALJs believe that the criticisms leveled at Dr. Hadaway’s ROE
recommendation are generally correct, certainly to the point that the ultimate recommendation is so
high as to be an outlier. The ALJs conclude that the proper range of acceptable ROEs would be
from 9.3 percent to 10.0 percent. This is actually confirmed by ETI’s own witness, Mr. Barrileaux,
who testified that, from a cash flow metric standpoint, an ROE of 9.99 percent would provide “a
reasonable outcome that balances debt and equity financing.”274


          The mid-point of the range discussed above is 9.65 percent. There has been a tremendous
amount of testimony about the unsettled economic conditions facing utilities and the effect of those
conditions on the appropriate ROE. The ALJs believe that this is an effect that must be taken into
account, and that the effect would be to move the ultimate ROE towards the upper limits of the range
determined to be reasonable. In this case, the ALJs find that the reasonable adjustment would be
15 basis points, moving the reasonable ROE to 9.80 percent. Accordingly, the ALJs recommend
that the Commission find that 9.80 percent is the appropriate ROE for ETI.




273
      Tr. at 1795.
274
      ETI Ex. 44 (Barrileaux Rebuttal) at 5, Ex. CEB-R-1.
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C.        Cost of Debt

          ETI’s weighted average cost of debt at the end of the test year was 6.74 percent.275 No party
has taken issue with that cost of debt. Therefore, the ALJs recommend that the Commission enter an
order finding that the appropriate cost of debt for ETI is 6.74 percent.


D.        Overall Rate of Return

          The overall rate of return is a product of the capital structure, ROE, and cost of debt. Based
on the discussions set forth above, the ALJs recommend that the Commission adopt the following
overall rate of return for ETI:


                                                                                  Weighted
           Component                   Cost                    Weighting           Cost
          Debt                         6.74                     50.08%             3.38
          Equity                       9.80                     49.92%             4.89
          Overall                                                                  8.27

  VII.      OPERATING EXPENSES [Germane to Preliminary Order Issue Nos. 2, 3, 4,
                                     and 16]

A.        Purchased Power Capacity Expense [Germane to Supplemental Preliminary Order
          Issue No. 1]

          One of the most hotly contested issues in this case concerned the appropriate size of ETI’s
purchased power capacity costs (PPCCs). In order to understand this issue, it is necessary to
understand some background relative to how ETI obtains and uses power generation capacity.


          1. The Sources of ETI’s Purchased Power

          The Entergy System Agreement is a FERC-approved tariff that mandates that the Operating
Companies operate as a single, integrated system.276 The System Agreement’s essential function is
to provide the contractual basis for the planning, construction, and operation of generation and

275
      ETI Ex. 5 (Barrilleaux Direct) at 37.
276
      ETI Ex. 30 (Jaycox Direct) at 5-6; ETI Ex. 39 (Cicio Direct) at 6-10.
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transmission resources in an economic and reliable manner. By jointly planning and operating their
electric systems, the Operating Companies believe they are able to aggregate their loads and jointly
dispatch their resources to serve that load using the lowest cost resources available from all of the
Operating Companies, resulting in lower total costs than the total cost of each Operating Company
planning and operating separately. Another function of the Entergy System Agreement is to provide
a basis for the equalization among the Operating Companies of any imbalances of costs arising from
the construction, ownership, or operation of facilities that are used for the collective benefit of all
Entergy Operating Companies.277


          To provide reliable service, ETI must have sufficient generation capacity to meet the
maximum demands imposed on its system. Some of this generation capacity (approximately
1,200 MW) is generating plants owned and operated by ETI.278 The remainder of ETI’s capacity
comes from four types of purchased capacity: (1) capacity purchases from third parties; (2) capacity
purchases from other Entergy affiliates through “legacy affiliate contracts” under MSS-4;
(3) capacity purchases from other Entergy affiliates through “other affiliate contracts” under MSS-4;
and (4) capacity purchases from the Entergy system through reserve equalization payments under
MSS-1.279 MSS-1 and MSS-4 are schedules included in the Entergy System Agreement which set
out complex mathematical formulas whereby the various Operating Companies can equalize and
share the costs of power capacity among themselves.280 These four sources of purchased capacity
are inversely related to one another: the more ETI purchases from one source, the less it needs to
purchase from the others.281

              ¾ Capacity Purchases from Third Parties

          Third-party capacity contracts are contracts that the system has allocated in whole or part to
ETI.      ETI has contracted to purchase capacity from a number of third parties, including


277
      ETI Ex. 39 (Cicio Direct) at 6, 8-10, 11-30.
278
      Tr. at 1539-40.
279
      ETI Ex. 34 (Cooper Direct) at 20-21; Tr. at 1901; ETI Initial Brief at 71.
280
      ETI Ex. 39 (Cicio Direct) at PJC-1, pp. 30 and 62.
281
      Tr. at 1946-47.
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ConocoPhillips-SRW, Dow Pipeline, Frontier, Calpine-Carville, and Sam Rayburn Municipal Power
Agency (SRMPA). Since 2009, ETI has been in the process of substantially increasing its reliance
upon third party purchases of capacity. During the Rate Year, it plans to more than double the
amount of capacity it purchases from third parties as compared to the amount it purchased during the
Test Year.282


            Since the Test Year, Entergy has been engaged in an effort to increase ETI’s long-term
power capacity through dealing with third parties. It has entered into a number of agreements in that
regard:


x      In 2009, it entered into a ten-year purchased power agreement with Calpine Energy Services
       (Calpine) to purchase 485 MW of capacity from Calpine’s Carville Energy Center (Carville
       Contract). Purchases pursuant to the Carville Contract will commence during the Rate Year, on
       June 1, 2012, and 50 percent of this contract is allocated to ETI.283

x      During the Period from July 2009 through June 2011, the Company executed an agreement with
       NRG for a 75 MW one-year call option, with a delivery period that began on March 1, 2011, and
       100 percent of this contract is allocated to ETI.284

x      During the Period from July 2009 through June 2011, the Company executed a three-year
       agreement with Dow Pipeline for 100 MW capacity, with a delivery period that began on April
       1, 2011, and 100 percent of this contract is allocated to ETI.285

x      During the Period from July 2009 through June 2011, the Company executed a 25-year
       agreement with SRMPA for 225 MW, with a delivery period beginning on December 1, 2011,
       and 100 percent of this contract is allocated to ETI. ETI contends that the SRMPA contract will
       be beneficial because it provides “much-needed long-term base load capacity at an economically
       attractive price.”286




282
      ETI Ex. 34 (Cooper Direct) at 23; see also ETI Init. Br. at 75-76.
283
      ETI Ex. 34 (Cooper Direct) at 16, 19.
284
      ETI Ex. 34 (Cooper Direct) at 16, 19.
285
      Id. at 17, 19.
286
      Id.
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x      An additional contract, the Frontier contract, was in place during the Test Year, and saw a
       150 MW increase in contract capacity during the Test Year.287

           ETI argues that its growing reliance on third-party purchases will diversify its energy
portfolio and help the Company meet its reliability needs at a lower cost.288 The new purchased
power contracts will also reduce ETI’s fuel costs and dependence upon aging, higher heat rate
generation units within the Entergy system.289


               ¾ Capacity Purchases from Other Entergy Affiliates Through “Legacy” Affiliate
                 Contracts Under MSS-4

           The term “legacy affiliate contracts” refers to those contracts resulting from the
December 31, 2007, jurisdictional separation of EGSI into ETI and EGSL, pursuant to which ETI
purchases its allocated share of power from plants such as the River Bend nuclear plant, located in
Louisiana and owned by EGSL as a result of the separation. The legacy affiliate purchases are made
under MSS-4.290


               ¾ Capacity Purchases from Other Entergy Affiliates Through “Other” Affiliate
                 Contracts Under MSS-4

           “Other affiliate contracts” refers to all affiliate contracts other than legacy contracts whereby
ETI purchases capacity and associated energy from other Operating Companies.291 The other
affiliate purchases are also made under MSS-4.292 Among others, in 2009 ETI entered into a new
affiliate contract with Entergy Arkansas, Inc. (EAI) for wholesale base load resources (the EA WBL
Contract), whereby ETI was allocated 31.7 percent of 336 MW capacity.293



287
      Tr. 1937-38.
288
      ETI Ex. 34 (Cooper Direct) at 24.
289
      Tr. at 1112-13, 1940-41.
290
      ETI Ex. 39 (Cicio Direct) at 24-26.
291
      ETI Ex. 34 (Cooper Direct) at 21.
292
      ETI Ex. 39 (Cicio Direct) at 24-26.
293
      Cities Ex. 6 (Nalepa Direct) at 13-14.
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              ¾ Capacity Purchases from the Entergy System Through Reserve Equalization
                Payments Under MSS-1

          Reserve Equalization payments are made under MSS-1. In any given month, some of the
Operating Companies might be “long” on the amount of generating capacity they own (meaning that
they own more capacity than they need) while others might be “short” on capacity (meaning they
own less capacity than they need). In such a month, the long Operating Companies would receive
MSS-1 payments from the short Operating Companies for use of their capacity.294


          2. ETI’s Request Regarding PPCCs

          During the Test Year, ETI had total PPCCs of $245,432,884.295 In the application, however,
ETI is not seeking to recover its Test Year expenses. Rather, it is asking to recover roughly
$276 million, which represents the Company’s anticipated PPCCs in the Rate Year.296 In other
words, ETI is seeking roughly $31 million more than its actual Test Year expenses. ETI derived this
estimate based largely upon what it believes will the purchased power agreements in place during
the Rate Year.297


          As the following tables illustrate, ETI projects that, during the Rate Year, the total quantity,
and the relative quantities purchased from each source, will differ substantially from its Test Year
purchases.


                        Test Year vs. Rate Year Power Capacity Quantities
                                         (MW-Months)298
                         Purchase                Test Year        Rate Year
                  Third Party Purchases            5,884           12,834



294
      ETI Ex. 39 (Cicio Direct) at 11-13; Cities Ex. 4 (Goins Direct) at 13.
295
      TIEC Ex. 1 (Pollack Direct) at Ex. JP-1; Tr. at 652-53.
296
   TIEC Ex. 1 (Pollack Direct) at JP-1; ETI Ex. 34 (Cooper Direct) at 20; ETI Ex. 34A (Errata to Cooper
Direct).
297
      TIEC Ex. 1 (Pollack Direct) at 22.
298
      TIEC Ex. 1 (Pollack Direct) at 22, Table 1 (Errata).
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                         Test Year vs. Rate Year Power Capacity Quantities
                                          (MW-Months)298
                           Purchase               Test Year        Rate Year
                  Affiliate Purchases (both        21,670           21,711
                  Legacy and Other) Under
                  MSS-4
                  Reserve Equalization              8,309            5,262
                  Under MSS-1
                  Total                            35,863           39,807


                           Test Year vs. Rate Year Power Capacity Costs299
                           Purchase                Test Year         Rate Year
                  Third Party Purchases           $32,094,893       $69,061,200
                  Affiliate Purchases (both      $189,032,442      $188,430,917
                  Legacy and Other) Under
                  MSS-4
                  Reserve Equalization            $25,461,353       $18,317,367
                  Under MSS-1
                  Total                         $246,588,688300    $275,809,484

          This indicates ETI will purchase roughly 11 percent more power in the Rate Year than it did
in the Test Year. Moreover, while the purchases pursuant to MSS-4 will remain fairly stable, the
third-party purchases will substantially increase, with a somewhat corresponding decrease for
purchases pursuant to MSS-1. In other word, ETI’s plan is to become “less short” (on capacity)
relative to the other Operating Companies in the Rate Year than it was in the Test Year.


          ETI contends that the shift toward more third party purchases is part of its effort to develop a
more diverse, modern, and efficient portfolio of generation supply resources, both to serve current
customer needs and to serve anticipated load growth. This, in turn, will lower energy costs and
result in savings for customers.301


          ETI’s initial request in this case was for a Purchased Power Rider (PPR) that would allow the
Company to recover $276 million, but would be subject to future reconciliation based on actual

299
      Cities Ex. 12.
300
      Cities now agree that the correct amount for the Test Year is $245,432,884. See TIEC Reply Brief at 18.
301
      ETI Ex. 47 (Cooper Rebuttal) at 7-8.
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expenses and revenues, much like a fuel factor.302 The intervenors point out that the PPR proposal,
while unprecedented, would have at least matched any post-Test Year increases in total purchased
capacity costs with corresponding increases in sales, and would also have allowed for a prudence
review of any post-Test Year purchased power capacity expenses in a future reconciliation
proceeding.303         The Commission, however, rejected the PPR proposal in its Supplemental
Preliminary Order.304 In lieu of the PPR proposal, ETI now proposes to simply recover the
$276 million as part of its base rates.


           3. Staff and Intervenors’ Opposition to ETI’s PPCCs Proposal

           Staff and all of the actively-engaged intervenors oppose ETI’s proposed adjustment to its
Test Year PPCCs. They make a number of arguments against ETI’s proposal.


                         (a) The PPCCs Requested by ETI Are Not Known and Measurable

           First, they contend that ETI’s Rate Year forecast cannot be considered known or measurable.
Staff points out that the four305 components from which ETI purchases power are interrelated, such
that, “when ETI adds capacity under one element, such as through third party contracts, the other
components, such as ETI’s MSS-1 payments, will decrease.”306 Staff describes each of the
components comprising ETI’s PPCC Rate Year forecast as being “infected” with numerous
assumptions.307 For example, ETI necessarily made projections, rather than relying upon actual
payments, when it estimated what it will pay for third-party contracts in the Rate Year.308 Many of
the third party contracts that will be in effect in the Rate Year do not contain fixed price terms.
Rather, the amounts ETI will pay will fluctuate based upon factors such as required availability and

302
      Tr. at 1954; Cities Ex. 4 (Goins Direct) at 14.
303
      TIEC Init. Br. at 25-26; Tr. at 1954; Cities Init. Br. at 37; Cities Ex. 6 (Nalepa Direct) at 8.
304
      Supplemental Preliminary Order at 2 (Jan. 9, 2012).
305
  Staff (and some of the intervenors) describe them as three components, by combining affiliate purchases
under legacy contracts and affiliate purchases under other contracts into one component.
306
      Staff Initial Brief at 25 (citing Tr. at 1946).
307
      Staff Initial Brief at 26.
308
      Tr. at 704.
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performance. Nevertheless, ETI simply assumed it would pay the maximum amount possible under
each of its third party contracts, and disregarded any of the contractual factors that might reduce its
Rate Year payments.309 Thus, the intervenors contend that ETI’s cost estimates for third party
purchased power are merely projections, as opposed to known and measurable changes.310


           Similarly, ETI’s contractual agreements with its affiliate Operating Companies require ETI
to make assumptions about their future costs. The contracts do not definitively fix prices or
quantities. Rather, prices and quantities under the contracts will fluctuate based on the specific
operational conditions actually experienced by the various Operating Companies during the Rate
Year.311 The ultimate determination of payments made in the Rate Year will be calculated based
upon the complex mathematical formula set out in schedule MSS-4. That formula contains a great
number of variables. ETI had to make assumptions about each one of those variables in order to
estimate its Rate Year costs.312 The intervenors point to ETI’s new contract with EAI (the EA WBL
Contract) as evidence of the “inherently speculative nature” of ETI’s PPCCs request. According to
the intervenors:

x      the EA WBL Contract was signed on April 11, 2012 (only days before the hearing in this matter
       commenced); purchases will not commence under the contract until January 1, 2013;

x      pricing under the contract will be determined in 2013 pursuant to the complex formula contained
       in MSS-4;

x      the quantity of capacity ETI ultimately purchases under the contract will be based on a yet-to-be-
       determined allocation percentage between ETI and the other Operating Companies;

x      the contract itself may never go into effect because it is contingent upon ETI receiving all
       necessary “regulatory approvals” before August 1, 2012; and

x      if it does go into effect, it will still be subject to at least two further revisions before any power is
       received by ETI under the contract.313

309
      Tr. at 704-05.
310
      TIEC Initial Brief at 29-30; Staff Initial Brief at 26.
311
      Tr. at 606.
312
      See Staff Initial Brief at 27; Tr. 606.
313
      ETI Ex. 47 (Cooper Rebuttal) at RRC-R-1, and Tr. at 628-9.
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The EA WBL Contract accounts for more than one-third of ETI’s upward adjustment to its Test
Year PPCCs. The intervenors contend that, in order for ETI to arrive at its forecasted PPCCs for the
Rate Year, it had to make myriad assumptions as to the future values of the many variables in the EA
WBL Contract (and the other affiliate contracts).314 Therefore, the intervenors argue that ETI’s cost
estimates for its contractual agreements with its affiliate Operating Companies are merely
projections, as opposed to known and measurable changes.315


          ETI’s estimated costs for its MSS-1 payments also require assumptions about the future. In
order to calculate its future reserve equalization responsibilities using the complex formula set out in
MSS-1, ETI had to forecast its own future loads, along with the future loads of all the other
Operating Companies. If those assumptions prove to be wrong, then ETI’s actual MSS-1 costs will
be different than as projected in the application.316 It is noteworthy, according to the intervenors,
that ETI projected the future load growths of all the Operating Companies when it calculated its
projected Rate Year MSS-1 costs because, elsewhere in ETI’s evidence, the Company has taken the
position that future projected loads should not be considered known and measurable.317 Staff argues:


          ETI cannot have it both ways. It cannot claim load growth to be speculative in one
          context, and then claim that it can forecast with absolute certainty the respective load
          growths for each EOC on the Entergy System.318

TIEC points out that ETI’s estimated MSS-1 payments “were still changing on the eve of the
hearing.”319 In the following exchange, even ETI witness Phillip May, one of the Company’s




314
    Staff Initial Brief at 27-28. Staff makes the further point that, because the EA WBL Contract was
executed only days before the hearing, Staff has been unable to determine whether the contract is even a
prudent one.
315
      TIEC Initial Brief at 30-32; Staff Initial Brief at 27-28.
316
      Tr. at 651-52.
317
      Tr. at 1907; see also Staff Initial Brief at 28; TIEC Initial Brief at 27-28.
318
      Staff Initial Brief at 29; see also TIEC Initial Brief at 37.
319
      TIEC Initial Brief at 28.
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primary witnesses regarding its PPCCs, seems to have conceded that the Company’s MSS-1
projections are not known and measurable:


           Q:       Do you think that the projection . . . of rate year sales that is implicit in the
                    calculation of MSS-1 costs . . . is a known and measurable change?
           A:       I think that there is some uncertainty with regard to that projection, yes,
                    sir.320

In sum, the intervenors contend that ETI’s cost estimates for all components of purchased power in
the Rate Year are merely projections, as opposed to known and measurable changes.321


                         (b) The PPCCs Requested by ETI Violate the Matching Principle

           Second, the intervenors acknowledge the principle that Test Year expenses may be adjusted
for known and measurable changes. However, they contend that such adjustments can only be made
where the attendant impacts on all aspects of a utility’s operations (including revenue, expenses, and
invested capital) can with reasonable certainty be identified, quantified, and matched.322 They assert
that ETI’s proposed adjustment does not satisfy this matching principle. The intervenors complain
that ETI is improperly attempting to “compare apples to oranges” by mixing a forecast of future Rate
Year PPCCs with actual Test Year billing determinants. As explained by Cities witness Nalepa,
“[u]nder the company’s approach of mixing estimated rate year costs with test year billing units,
there is a failure to recognize customer growth and increased sales revenue – thus overstating the
revenue requirement.”323 The argument, essentially, is that the various new or expanded contracts
that ETI has entered into were executed so that, in whole or in part, ETI would be able to meet future
demand, but that ETI is seeking to recover the costs of those new contracts from its existing
customers.324



320
      Tr. at 1918-19.
321
      TIEC Initial Brief at 27-28; Staff Initial Brief at 29.
322
      Cities Ex. 6 (Nalepa Direct) at 12, citing P.U.C. SUBST. R. 25.231(c)(2)(F).
323
      Cities Ex. 6 (Nalepa Direct) at 8; Cities Ex. 4 (Goins Direct) at 14-15.
324
      Cities Ex. 6 (Nalepa Direct) at 11; see also Cities Initial Brief at 38, Staff’s Initial Brief at 30, TIEC Initial
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           The intervenors offer various examples, of which the following is typical, to illustrate why it
was inappropriate for ETI to fail to take load growth into account when it calculated its Rate Year
PPCCs. Assume that, during the Test Year, Utility X had 100 billing units and $500 of PPCCs. Also
assume that, during the Rate Year, Utility X had 200 billing units and $1,000 of PPCCs. If Utility X
were limited to setting its rates based solely on its Test Year numbers, then it would recover
precisely the right amount to cover its PPCCs in both the Test Year (100 billing units x $5 per unit =
$500 of PPCCs) and in the Rate Year (200 billing units x $5 per unit = $1,000 of PPCCs). If, on the
other hand, Utility X were allowed to set its rates based upon it billing units from the Test Year
(100) and its PPCCs from the Rate Year ($1,000), then Utility X would unfairly recover twice the
amount needed to cover its actual PPCCs in the Rate Year (200 billing units x $10 per unit =
$2,000).325 Thus, intervenors contend that ETI’s load growth must be taken into account if PPCCs
are to be based on Rate Year projections.326 They point out that ETI itself expects steady load
growth in the next few years,327 and experienced “good” growth over the two years preceding the
Test Year.328


           For its part, ETI denies that its increased capacity has been obtained in order to meet load
growth. Rather, it contends that it has added capacity in order to be “less short” in comparison to the
other Operating Companies.329 Moreover, ETI contends that the load growth adjustments proposed
by intervenors are “uncertain and unnecessary.”330


                       (c) ETI’s Proposal Would Preclude Prudence Review

           Third, TIEC contends that ETI’s future Rate Year proposal would set rates based on
projections without any effective Commission review of: (1) what the actual expenditures under


Brief at 35-39.
325
      Cities Ex. 4 (Goins Direct) at 16-17.
326
      Cities Ex. 4 (Goins Direct) at 17; see also TIEC Ex. 23.
327
      Cities Ex. 4 (Goins Direct) at 17; Tr. at 706.
328
      Tr. at 130.
329
      ETI Initial Brief at 68-69.
330
      Id. at 69.
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purchased capacity contracts turn out to be; (2) whether those expenditures turn out to be reasonable;
and (3) whether the future contracts were prudent.331


           4. The Intervenors’ Recommendations Regarding PPCCs

           The intervenors agree that the amount requested by ETI is unreasonable, excessive, and
should be rejected. They do not universally agree, however, about what the proper number for
PPCCs should be. Staff, TIEC, and State Agencies argue that ETI’s PPCCs should be set at the
amount of the Company’s Test Year PPCCs: $245.4 million. This position is best summarized by
Staff:


           Staff recommends that the Commission adhere to traditional ratemaking principles
           and set the amount of ETI’s purchased power expenses based on what the Company
           actually experienced during its test year. During its test year, ETI had total
           purchased power capacity expenses of $245.4 million. This amount is not in dispute.
            This amount is known. This amount is measurable. The Commission should utilize
           this amount to set just and reasonable rates for ETI and its ratepayers.332

           Rather than recommending Test Year PPCCs, Cities offer two alternatives – one
recommended by its witness Dr. Dennis Goins, and another recommended by its witness
Mr. Nalepa.333        Dr. Goins recommends that ETI be allowed to recover PPCCs of roughly
$242.9 million.334 This amount is roughly $33 million less than ETI’s requested amount and
$3 million less than ETI’s actual Test Year costs. To arrive at this amount, Dr. Goins made several
calculations. First, he adjusted the average per kW cost of ETI’s legacy and other affiliate purchases
using cost data from November 2010 through October 2011, which is slightly more current data than
that relied upon by ETI.335 Second, as to MSS-4 costs, because the EA WBL contract is set to expire
sooner than the three years he assumed ETI’s new rates will be in effect, Dr. Goins “normalized” the



331
      TIEC Initial Brief at 33-35.
332
      Staff Initial Brief at 29.
333
      Cities Initial Brief at 40.
334
      Cities Ex. 6 (Nalepa Direct) at 17, and Errata No. 3.
335
      Cities Ex. 4 (Goins Direct) at 17-18.
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costs of the EA WBL contract over the three year period.336 Finally, he adjusted the Rate Year total
PPCCs estimate to reflect the effects of load growth, based upon ETI forecasts.337


          Mr. Nalepa took a slightly different approach. He recommended that ETI be allowed to
recover PPCCs of $236,838,634, or roughly $39 million less than ETI’s requested amount and
$8 million less than ETI’s Test Year costs.338 To arrive at this amount, Mr. Nalepa first calculated
the per kW cost of ETI’s third party Rate Year capacity and applied it to ETI’s Test Year-end
capacity. In this way, “the increased cost of the new resources is recognized, but current demand is
better matched to current resources.”339 Second, he made the same adjustment as Dr. Goins as to
MSS-4 costs due to the EA WBL contract.340


          TIEC explains it is reluctant to “descend into the rabbit hole and engage in ratemaking based
on prognostications, estimates, projections, and assumptions about what may happen in the
future.”341 If the Commission were to do so, however, TIEC argues that the final result would be
lower than the Test Year PPCCs, not higher. TIEC’s witness Jeffry Pollock calculated the impact of
projected unit prices based upon ETI’s projections, and he eliminated the expiring EA WBL
Contract. His result, which TIEC is not advocating, would allow ETI to recover PPCCs of $238.8
million, roughly $7 million less than its Test Year costs.342


          ETI describes the proposals made by TIEC and Cities as “extreme” and contrary to common
sense.343 For example, Mr. Pollock’s calculations indicate that ETI’s MSS-1 costs would increase
by roughly $5 million, while its third-party and affiliate contracts would slightly decrease. ETI
argues that this is the opposite of reality. By adding capacity through third party contracts, its

336
      Cities Ex. 4 (Goins Direct) at 18; Cities Ex. 6 (Nalepa Direct) at 15-16.
337
      Cities Ex. 4 (Goins Direct) at 18-19.
338
      Cities Ex. 6 (Nalepa Direct) at 17.
339
      Cities Ex. 6 (Nalepa Direct) at 12-13.
340
      Id. at 15-16.
341
      TIEC Initial Brief at 41.
342
      TIEC Ex. 1 (Pollack Direct) at 25-27; TIEC Initial Brief at 41-42.
343
      ETI Initial Brief at 83.
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reliance upon the other purchased power components, especially MSS-1, will necessarily decline,
not increase.344 ETI also argues that load growth is inherently uncertain and should not be taken into
account.345


          5. The ALJs’ Analysis Regarding PPCCs

          The ALJs conclude that ETI failed to meet its burden to prove that the adjustment it seeks to
its Test Year PPCCs is known and measurable. The known and measurable standard is an exception
to the actual data contained in the Test Year. The point of a historical Test Year is to review actual
costs, which include the ups and downs of what actually occurred. As to a forecast of the Rate Year,
by contrast, the evidence demonstrates that the costs attributable to a particular contract to purchase
capacity cannot currently be known because there are so many variables that will play into the
amount ETI ultimately pays. As stated above, ETI’s third party contracts lack fixed prices and the
amounts ETI will pay could fluctuate based upon factors such as required availability and
performance. ETI simply assumed it would pay the maximum amounts under those contracts, and
disregarded the contractual factors that could lower the payment amounts. Yet this assumption runs
counter to ETI’s historical experience with its contracts.346 Similarly, ETI’s affiliate contracts do not
fix prices or quantities, and the amount ETI ultimately pays will fluctuate based upon operational
conditions experienced by all of the Operating Companies during the Rate Year. Those operational
conditions obviously cannot be known at this time. Both the affiliate contracts under MSS-4 and the
equalization payments under MSS-1 are based upon highly complex mathematical formulae that
utilize numerous variables. Any of the variables could change during the Rate Year, thereby altering
the amounts paid by ETI under affiliate contracts or MSS-1. As a result, the evidence demonstrates
that there could be a substantial difference between ETI’s projected Rate Year costs and what
actually ends up occurring. ETI asks the Commission to trust it that these differences would be
“small,”347 but provides no evidence as to what small means.


344
      Id. 83.
345
      Id. 84.
346
      Tr. at 705.
347
      ETI Initial Brief at 81.
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          The efforts made by ETI, Cities, and TIEC to forecast Rate Year PPCCs further illustrate the
difficulty of deviating from actual Test Year data in an area that involves so many future
contingencies and unknowns. Those forecasts swung wildly – ETI estimated Rate Year PPCCs that
were $31 million more than the Test Year, while the Cities’ and TIEC’s estimates came in at $3
million, $8 million, and $7 million less than the Test Year, respectively. Indeed, even Cities’ own
witnesses disagreed substantially among themselves as to what the proper amount should be.
Moreover, arguably ETI could not even agree with itself regarding the proper amount because, in its
Initial Brief, it suggested that a reduction of roughly $4.5 million might be warranted to account for
its latest projection of its MSS-1 costs in the Rate Year.348


          The ALJs are similarly convinced that ETI’s request violated the matching principle by
mixing its forecast of future Rate Year PPCCs with Test Year billing determinants. It is logically
inconsistent for ETI to have, on the one hand, based its estimate of Rate Year MSS-1 costs on its
projections of the load growths of ETI and all the other Operating Companies and, on the other hand,
argue that load growth cannot be considered known and measurable when calculating its overall
PPCCs. This argument does not withstand scrutiny, especially in light of the fact that ETI clearly
believes its load will be larger in the Rate Year than it was in the Test Year and it has, in fact,
contracted for six percent more load in the Rate Year.349


          Simply put, the intervenors presented substantial evidence that all of the components of
ETI’s purchased power capacity contain significant variability and uncertainty in costs, thereby
leading to the conclusion that estimates of Rate Year PPCCs cannot be considered known and
measurable. For this reason, the ALJs recommend that ETI’s PPCCs request be rejected. In its
place, the ALJs recommend that ETI be allowed to recover its Test Year PPCCs of $245,432,884.




348
      ETI Initial Brief at 77 (citing Tr. at 684, 1945).
349
      ETI Ex. 47 (Cooper Rebuttal) at 4; Tr. at 667-68.
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B.         Transmission Equalization (MSS-2) Expense

           The Entergy system transmission grid is a large, integrated transmission network that is
operated for the mutual benefit of all of the Entergy Operating Companies.350                 Service
Schedule MSS-2 is a FERC jurisdictional tariff that equalizes the ownership costs of certain high
voltage transmission facilities among ETI and the other Operating Companies, so that each
Operating Company pays its just and reasonable share of those costs. Accordingly, those costs are
referred to as “transmission equalization” payments.351 MSS-2 generally applies to equalization of
transmission costs for transmission assets of 230 kV and larger.352


           In any given month, some of the Operating Companies might be “long” on the amount of
transmission capacity they own (meaning that they own more capacity than they need) while others
might be “short” on capacity (meaning they own less capacity than they need). In such a month, the
long Operating Companies would receive MSS-2 payments from the short Operating Companies for
use of their transmission facilities.353 Over the course of the Test Year, ETI was short, meaning that
it paid a total of $1,753,797 in MSS-2 payments to various other Operating Companies.354


           In the application, rather than seeking to recover only the $1.7 million in Test Year MSS-2
costs, ETI is seeking to recover roughly $10.7 million, which represents its anticipated MSS-2
expenses in the Rate Year.355 The additional $9 million that ETI seeks is based on the Company’s
estimates of transmission construction projects that are expected to have been completed by or
during the Rate Year which will result in changes to the relative transmission line ownership ratios
between the Operating Companies. In other words, ETI expects that, by or during the Rate Year, its
ownership share under the MSS-2 will decrease relative to the other Operating Companies (as the



350
      Tr. at 450, 793.
351
      Tr. at 724; ETI Ex. 39 (Cicio Direct) at 15-17 and PJC-1 at 38.
352
      Tr. at 450-51, 731.
353
      Tr. at 731, 735.
354
      Tr. at 723-24, 737; Cities Ex. 28.
355
      Tr. at 452-53, 738, 760.
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transmission capacity owned by the other Operating Companies increases), thereby driving the
amount of ETI’s MSS-2 payments upward.356


            The increase is driven by ETI’s prediction that $184.9 million in additional transmission
capacity will be built by other Operating Companies by the end of the Rate Year. ETI identified six
construction projects that are either underway or approved for construction and which, collectively,
will account for roughly $141 million of the predicted $184.9 million in additional transmission
capacity. Of those six projects, one was completed and went into service on December 16, 2011,
after the end of the Test Year. The other five are either under construction or still in the planning
phase and are currently scheduled to go into service on dates ranging from June 29, 2012, to
December 31, 2012.357 According to ETI, the remaining $43.9 million of the $184.9 million in
additional transmission capacity is derived from “an estimate of the capital investment necessary to
maintain equalizable [i.e. MSS-2 qualifying] transmission investments across the Entergy
Transmission System.”358 The estimate is based upon the Operating Company’s projected budgets
and historical spending patterns for maintenance of transmission facilities.359


            Staff, State Agencies, TIEC, and Cities all oppose ETI’s effort to recover $10.7 million in
MSS-2 expenses. The parties make a number of arguments. First, they point out that MSS-2 utilizes
a complex mathematical formula to calculate each Operating Company’s liability (or credit) under
the equalization process. There are a great number of variables that are used in the formula, such as
the amount of investments made by each Operating Company in transmission facilities, the costs of
capital for each Operating Company, the size of the load demanded by each Operating Company,
and the amount of state and federal taxes paid by each Operating Company. Changes to any of these
variables can change the amount ETI owes (or is due) pursuant to MSS-2.360 Moreover, these
variables relate not only to ETI, but to all of the Operating Companies. Indeed, Cities calculate that,


356
      Tr. at 775-77.
357
      ETI Ex. 59 (McCulla Rebuttal) at 2 and MFM-R-1; Tr. at 456-58.
358
      ETI Ex. 59 (McCulla Rebuttal) at 3.
359
      Id.
360
      ETI Ex. 39 (Cicio Direct) at PJC-1 at 38-43; Tr. at 454-55.
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to perform the MSS-2 calculation, at least 360 “mini-forecasts” must be made, only 60 of which
relate to ETI.361 As explained by TIEC witness Pollock, any effort to estimate future amounts of
these many variables “is susceptible to a host of uncertainties.”362 The intervenors argue that for
ETI to arrive at its estimate of $10.7 in MSS-2 costs during the Rate Year, the Company had to
speculate as to what the many MSS-2 variables would be in the Rate Year. In other words, they
contend that ETI’s estimate of its future MSS-2 costs cannot possibly be considered “known and
measurable” and, therefore, is not recoverable.363 State Agencies and Staff liken ETI’s attempt to
obtain an MSS-2 adjustment for not-yet-complete construction projects to an impermissible request
to recover the costs of CWIP without having to meet PURA’s burden of proving that recovery is
necessary to protect the utilities financial integrity.364


           Second, the parties oppose ETI’s effort to recover its predicted MSS-2 expense in the Rate
Year point out that the primary driver of the increased costs over the Test Year comes from a
number of transmission projects that have not yet come into service, and are still in the planning or
construction phase. ETI concedes that if the projects do not actually come into service at the
currently estimated times, then the Company’s estimates of its MSS-2 costs during the Rate Year
will be inaccurate.365 Thus, Staff contends that ETI’s projections about future MSS-2 costs cannot
be considered known and measurable.366 Moreover, TIEC and Staff contend that ETI is effectively
seeking higher rates based upon expenses associated with projects that are not yet completed and,
therefore, the projects cannot be considered “used and useful.”367 As explained by TIEC:


           It would be bad public policy for the Commission to rely on speculative construction
           end dates to form the basis of a known and measurable change to test year costs.

361
      Cities Reply Br. at 68-69.
362
      TIEC Ex. 1 (Pollock Direct) at 29.
363
   Staff Initial Brief at 31; State Agencies Initial Brief at 11-13; TIEC Initial Brief at 44-45; Cities Initial
Brief at 44.
364
   State Agencies Initial Brief at 12 (citing PURA § 36.054; P.U.C. SUBST. R. 25.231(c)(2)(D)); Staff Reply
Brief at 20.
365
      Tr. at 800-801
366
      Staff Initial Brief at 32.
367
      TIEC Initial Brief at 47; Staff Initial Brief at 19-20.
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          ETI’s own witness Mr. Cicio admitted that in-service dates can be uncertain. . . .
          Similarly, costs can change upward or downward. For this reason, the Commission
          has typically followed the policy that proper ratemaking requires that a utility
          actually build the transmission infrastructure suggested by its projections, and then
          seek to account for that investment on a historical basis in a future rate case. In
          Docket No. 28906, for example, the Commission held that LCRA’s projections of
          future transmission investment did not support a finding that its projected capital
          needs satisfied the known and measurable test. It is similarly unreasonable for ETI
          to make a post-test year adjustment associated with transmission projects that are not
          serving any of its customers and that may or may not impact ETI’s transmission
          equalization expense, depending on when the projects are finally completed.368

          Third, in addition to the six transmission projects that are under development, another driver
of the increased costs over the Test Year comes from ETI’s estimate that $43.9 million will be spent
to maintain transmission investments across the Entergy Transmission System. The intervenors
contend that ETI has provided little to no evidentiary support for this estimate. State Agencies and
Cities also point out the unfairness of allowing ETI to begin recovering $10.7 million per year in its
rates immediately based upon new transmission facilities, even though many of those new facilities
will not come into service (and ETI will therefore not incur higher MSS-2 payments for those
facilities) for many months.369


          Fourth, Cities points out that Entergy and the various Operating Companies have announced
a plan to sell all of their transmission assets to a third party. That process is currently underway.
The evidence suggests that, if and when that transaction is complete, ETI’s MSS-2 expenses will
disappear.370


          Finally, TIEC argues that there is no need to grant ETI’s request for a pro forma adjustment
to its test year MSS-2 expenses because the Company can avail itself of a TCRF if its Rate Year
costs deviate substantially from its Test Year costs. Thus, if it turns out that ETI experiences an


368
      TIEC Initial Brief at 47 (citing Docket No. 28906, Order at 6).
369
      State Agencies Initial Brief at 12; Cities Initial Brief at 45.
370
    Cities Reply Brief at 67-68; Tr. at 113-14; Cities Ex. 4 (Goins Direct) at 20-21. Admittedly, if these
expenses disappear, ETI will still have to bear transmission expenses. However, it is impossible to know, at
this time, what those expenses would be.
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increase in its MSS-2 expenses during the Rate Year, the utility has cost recovery mechanisms at its
disposal that could make it whole in a timely manner.


           Staff and State Agencies argue that only $1.7 million (representing ETI’s actual Test Year
expenses) should be approved in this proceeding. TIEC witness Pollock recommends approving a
slight upward adjustment to account for the fact that ETI’s MSS-2 expenses were substantially
higher in the second six months of the Test Year than they were in the first six months. Mr. Pollock
and TIEC recommend a pro forma adjustment equal to twice the amount of MSS-2 payments
incurred by ETI in the second six months of the Test Year, or $2.7 million.371


           Cities’ witness Goins presented yet another alternative. Dr. Goins proposes to adjust the
projected Rate Year costs for known expenses incurred after the Test Year. He proposed reducing
the adjusted Rate Year MSS-2 expense to a Test Year level by applying a load growth adjustment
using ETI’s own projected load growth as a benchmark indicator of the reasonable anticipated level
of growth. (Cities invoke essentially the same “matching principle” argument regarding load growth
that they raised with respect to PPCCs). The result of Dr. Goins’ adjustment would be to would
allow ETI to recover $4,103,850 in MSS-2 expenses.372


           ETI responds to these arguments on a number of fronts. It contends that the main driver of
changes in MSS-2 expenses is the relative amount of equalizable transmission investment in the
transmission system by ETI and the other Operating Companies, compared to their proportionate
responsibility for that investment, based on each company’s responsibility ratio.373 ETI argues that
the other elements of the formula are relatively stable, and do not vary significantly from year to
year.374 ETI contends its requested level of MSS-2 expense is based on a known and measurable


371
      TIEC Ex. 1 (Pollack Direct) at 32-33.
372
      Cities Ex. 4 (Goins Direct) at 20-21.
373
   ETI Ex. 45 (Cicio Rebuttal) at 3-4. Responsibility Ratio is an allocator that reflects the relative
contribution of each Operating Company to the System’s coincident peak load – in other words, an Operating
Company’s coincident peak load divided by the System peak load, calculated on a rolling twelve-month
average. ETI Ex. 39 (Cicio Direct) at 12.
374
      Tr. at 763 and 780.
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change because it is based on the $184.9 million in additional transmission investment for all of the
Operating Companies that ETI knows will occur and can reasonably measure. ETI points out that
“the vast majority” of the planned transmission projects have received full funding approval and
have been constructed or are on schedule to be completed before the end of the Rate Year, while the
remaining amount is reasonably quantified and measured based on the budget and historical
spending for maintenance of equalizable transmission facilities.375


           ETI also argues that its actual MSS-2 expenses have steadily trended upward since the Test
Year. ETI explains as follows:


           [I]n the last month of the test year (June 2011), ETI’s payments began to increase
           significantly, as the balance of relative equalizable investment levels shifted among
           the Operating Companies. ETI’s actual monthly payments have climbed steadily ever
           since, reaching $698,289 in the most recent actual month’s bill (February 2012).
           Annualization of this most recent actual data yields an annual MSS-2 amount of
           $8.4 million, almost five times the test year level. In light of this trend in actual
           historical data, the notion of basing the MSS-2 expense in rates on the test year level
           is unreasonable on its face.376

Thus, ETI contends its requested expense level is “consistent” with actual recent historical levels of
MSS-2 expense.377


           ETI describes Cities’ concern regarding load growth as a “red herring.” ETI contends that
load growth is not the cause of changes in MSS-2 costs. Instead, its MSS-2 increases are driven by
the other Operating Companies’ transmission investments, “separate and apart from, and unaffected
by,” any increase in ETI’s load.378 Moreover, ETI contends that load growth adjustments are not




375
      ETI Ex. 59 (McCulla Rebuttal) at 2-3; ETI Initial Brief at 88-89.
376
      ETI Initial Brief at 90-91; Tr. at 784.
377
      ETI Initial Brief at 91.
378
      ETI Ex. 45 (Cicio Rebuttal) at 4-5; ETI Initial Brief at 93.
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known and measurable and are not the proper subject of a post-test year adjustment for ordinary
expenses such as MSS-2 costs.379


          Finally, if the Commission rejects its request for $10.7 million in MSS-2 costs, ETI suggests
annualizing the most recent period of its actual MSS-2 costs, by multiplying its February 2012 MSS-
2 bill times 12, resulting in an amount of $8,379,480. ETI contends this would be more
representative of expected Rate Year MSS-2 costs than the amounts proposed by the intervenors.380


          For largely the same reasons as were discussed relative to PPCCs, the ALJs conclude that
ETI failed to meet its burden to prove that its proposed Rate Year MSS-2 costs are known and
measurable. The MSS-2 formula requires assumptions about a great number of variables. Changes
to any of the variables could occur during the Rate Year, thereby altering the amount paid by (or
received by) ETI during the Rate Year. The projects that underlie ETI’s Rate Year request are
largely not yet built, and might never be built. Additionally, much like with the PPCCs estimates,
there is a wide gulf between the competing estimates by ETI, Cities, and TIEC of forecast Rate Year
MSS-2 costs, illustrating the problem of deviating from actual Test Year data in an area that involves
so many future contingencies and unknowns.


          The ALJs are equally unconvinced by ETI’s alternative proposal to multiply its February
2012 MSS-2 bill times 12, resulting in an amount of $8,379,480. ETI offered no evidence to
establish that a single month’s costs can serve as a reasonable representation of what ETI’s future
Rate Year MSS-2 costs will be. Moreover, February 2012 is outside of the Test Year.


          The intervenors presented substantial evidence to demonstrate that ETI’s estimate of its Rate
Year MSS-2 costs cannot be considered known and measurable. For this reason, the ALJs
recommend that ETI’s MSS-2 request be rejected. In its place, the ALJs recommend that ETI be
allowed to recover its Test Year MSS-2 costs of $1,753,797.



379
      ETI Ex. 57 (May Rebuttal) at 12; ETI Initial Brief at 93.
380
      ETI Ex. 46 (Considine Rebuttal) at 37; ETI Initial Brief at 32.
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C.        Depreciation Expense [Germane to Preliminary Order Issue No. 12]

          ETI currently has an annual depreciation expense of approximately $72.1 million. This
expense is based on the previously approved depreciation rates.381 ETI now requests depreciation
rates that would result in an annual depreciation expense of approximately $86 million. This
requested amount represents an increase in the annual depreciation expense of approximately
$13.9 million - almost 20 percent - from the current annual depreciation expense.382                The
depreciation expense ultimately included in retail rates, however, will be derived by applying the
Commission approved rates to the test year end plant balances as of June 30, 2011.


          The other parties have accepted the vast majority of ETI’s recommendations, but take issue
with the Company on a few issues related to generation, transmission, distribution, and general plant
accounts. Staff recommends an annual depreciation expense of approximately $78.2 million, an
increase of approximately $6.1 million from the current annual depreciation expense.383 Cities
recommend an annual depreciation expense of approximately $67.6 million.384


          The identical positions of ETI, Staff, and Cities on depreciation issues are set forth in the
following table:385


  Plant Group               Approved          ETI Proposal         Staff Proposal     Cities Proposal
Hydro                            $7,137                $245                  $245                  n/a
Production
Regional Trans.                  $685,351              $685,351          $685,351                    n/a
& Market
Operations
General                        $4,175,311             $5,946,949       $5,946,949                    n/a
Amortized Plant


381
      ETI Ex. 13 (Watson Direct) Attachment DAW-1. Appendix B at 3.
382
      ETI Ex. 13 (Watson Direct) at 7.
383
      Staff Ex. 2 (Mathis Direct) at 8.
384
      Cities Ex. 5C (Pous Depreciation Study) at 2.
385
    ETI Ex. 13 (Watson Direct) at 7; Staff Ex. 2 (Mathis Direct) at 7-8; Cities Ex. 5C (Pous Depreciation
Study) at 7, 8, and 34.
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          The differing positions of ETI, Staff, and Cities on depreciation issues are set forth in the
following table:386


  Plant Group               Approved           ETI Proposal           Staff Proposal        Cities Proposal
Steam                        $17,497,781         $18,660,946              $14,709,942                    n/a
Production
Transmission                  $13,679,827          $16,493,761            $16,417,727            $13,451,479
Plant
Distribution                  $32,110,774          $40,493,392            $38,806,863            $33,186,546
Plant
General Plant                   $3,943,450           $1,604,644             $1,604,644               $973,519
General Plant                           $0           $2,134,924                     $0                     n/a
Reserve
Deficiency
TOTAL                         $72,099,631          $86,020,212            $78,171,721                    n/a387

          The competing positions of ETI, Staff, and Cities reflected in the table above are primarily
the result of different: (1) net salvage rates for certain accounts; (2) remaining life parameters for
certain accounts; and (3) treatment of a potential general plant reserve deficiency. Cities witness
Pous also questions the reliability of the data employed by ETI witness Watson in the performance
of his study.


          An analysis of the competing net salvage rates and life parameters for each account is
presented in detail below, organized by plant and account group.


          1. Terminology and Methodology

          Depreciation is a method of allocating the loss of the service value, not restored by current
maintenance, over the useful life of an asset. This loss may be caused by wear and tear, decay,
obsolescence, or changes in demand.388


386
    ETI Ex. 13 (Watson Direct) at 7; Staff Ex. 2 (Mathis Direct) at 7-8; Cities Ex. 5C (Pous Depreciation
Study) at 7, 8, and 34.
387
    A total value of Cities’ adjustments in this format would be out of context and is therefore not provided in
this table.
388
      Staff Ex. 2 (Mathis Direct) at 8.
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          Within the context of a rate case, the purpose of depreciation is to allow a company to
recover the cost of an asset over the asset’s useful life. Ideally, the cost of the asset is spread out
evenly across the years the asset is in service, thus recovering the cost of the asset from the
customers who receive the benefit of the asset.389


          Both ETI and Staff use the remaining-life technique, average life group procedure, and
straight-line method to calculate the depreciation rate.390 The basic formula for the remaining life
technique is presented below.




          For example, if an asset has a book reserve ratio of 0.5 (i.e., 50 percent of the asset’s value
has already been recovered through prior depreciation expense), a net salvage ratio of zero (i.e., the
asset will cost nothing to retire, or all retiring costs will be recovered through its subsequent sale),
and the composite remaining life is ten years (i.e., the asset is expected to remain in service for
another ten years), then the depreciation rate will be 5 percent (i.e., {[(1 - 0.5 - 0) / 10 ] *100}).


          By operation of the remaining-life formula, a greater net salvage value will reduce the
numerator and result in a lower depreciation rate and a lower depreciation expense. Likewise, a
lower net salvage value will increase the numerator and result in a higher depreciation rate and a
higher depreciation expense. Similarly, a longer remaining-life will result in a lower depreciation
rate and lower depreciation expense, and a shorter remaining-life will result in a higher depreciation
rate and a higher depreciation expense.


          Because net salvage and remaining-life values are the two contested variables in the
remaining-life formula, a clear explanation of net salvage and remaining-life will be helpful.




389
      Staff Ex. 1 (Mathis Direct) at 8-9.
390
      ETI Ex. 13 (Watson Direct) at 15; Staff Ex. 2 (Mathis Direct) at 10-11.
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          Net Salvage Value. Net salvage is calculated by taking the amount received for an asset as a
result of its sale, reuse, or reimbursement, and subtracting that amount from the cost associated with
retiring the asset. This figure is then divided by the original cost of the asset to determine the net
salvage ratio. For example, if an asset with an original cost of $200 is resold for $20, but it costs the
owner $10 to ship the asset to the purchaser, then the net salvage value of that asset would be $10
($20 - $10), and the net salvage ratio of that asset would be 5 percent ($10/$200).


          ETI witness Watson and Staff witness Mathis used different methods of calculating a net
salvage rate.391 Mr. Watson took the average (mean) of recorded net salvage values for groups of
successive years (rolling bands), and then selected the net salvage rate from among these
averages.392 Ms. Mathis also used rolling band averages (means), but then took the median from a
representative group of rolling bands when the historical salvage data would have otherwise
produced what Mr. Watson considers skewed results.393


          Ms. Mathis’ method of calculating net salvage rates follows recent Commission precedent.394
As Mr. Watson explained at the hearing, it is appropriate to infer acceptance of a methodology by
looking at whether the Commission adopted the conclusions that the methodology produced.395 In
other words, if the Commission adopts the conclusions, then by inference the Commission has
adopted the methodology used to derive those conclusions. Thus, it is necessary to examine recent
litigated rate cases to ascertain Commission precedent.


          In the most recent fully-litigated rate case, Docket No. 38339,396 Staff disagreed with
CenterPoint’s depreciation witness, Mr. Watson, concerning the net salvage rates for five



391
      Tr. at 415-416.
392
      ETI Ex. 13 (Watson Direct) at 20-21.
393
      Id. at 22-23, 32-33.
394
      Tr. at 1766; Staff Ex. 9 (Docket No. 38339 Final Order) at FoF 126, 128, 130, and 131.
395
      Tr. at 397.
396
    Application of CenterPoint Energy Houston Electric, LLC, for Authority to Change Rates, Docket
No. 38339 (June 23, 2011).
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accounts.397 In its order, the Commission adopted Staff’s recommended net salvage rates for four
out of those five accounts for which Staff disagreed with Mr. Watson.398 Staff’s method for
calculating net salvage rates is the same in the present case as it was in the CenterPoint rate case.399


            ETI argues that the use of a median, as employed by Ms. Mathis, is not a sufficiently
rigorous or expansive approach to depreciation analysis. According to ETI, depreciation training
and texts, as well as authoritative statistical texts, favor the average, or mean, not the median, as the
best indicator of the central tendency of a data set. ETI argues that this is particularly the case
because depreciation analysis requires careful consideration of trends over time.400 ETI then offers
the following comments:


            [Ms. Mathis] agreed in response to a hypothetical that the median value of an initial
            period of ten years of +5% net salvage, followed by one year of 0% salvage,
            followed by the most recent period of ten years of -5% salvage, would be 0%. This
            hypothetical plainly illustrates how reliance on the median can overlook data trends.
            In the hypothetical, if the depreciation analyst would otherwise wish to give more
            weight to the most recent historical period as indicative of conditions going forward,
            the use of the median would obscure that important trend information.401

A close examination of the hypothetical shows that in the case posited by ETI, however, the median
and the mean are identical: both are zero. While the use of the median would produce a result that
ignores the trend that ETI says should be taken into account, the mean produces the same result.
Changing the hypothetical produces no more clarity. If the examination was of a period that had ten
years of positive five percent salvage value, followed by one year of zero percent net salvage value,
followed by the most recent 10-year period, which had negative 10 percent net salvage value, the
median would still be zero but the mean would be negative 2.38 percent. This appears to support the
trending argument advanced by ETI. If the analysis then focuses on a different hypothetical, one
with ten years of positive 10 percent net salvage value followed by one year of zero percent net

397
      Tr. at 401-402.
398
      See Staff Ex. 9 (Docket No. 38339 Final Order); Tr. at 402.
399
      Tr. at 415-416.
400
      ETI Initial Brief at 105.
401
      Id.
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salvage value, with the most recent ten-year period having negative five percent net salvage value,
the results are more perplexing. The median is still zero, but the mean, which ETI contends will
recognize the trending, is 2.38. Although this does in some respects recognize the trend to a
negative salvage value, it does not recognize it as well as the median.


       Principles and Procedures of Statistics, by Steel and Torrie, states: “Certain types of data
show a tendency to have a pronounced tail to the right or the left. Such distributions are said to be
skewed, and the arithmetic mean may not be the most informative central value.” Where the average
of the incomes of a group of individuals is required, and most of those incomes are low, the mean
income could be considerably larger than the median. In Docket No. 38339, Staff posed the
following example, which the ALJs found both informative and persuasive: Suppose a sample of
50 incomes from professional baseball players was taken that happened to include the salary of two
of the most highly compensated players in the league today. As a result, the mean of the salaries
would likely be far greater than the median salary, because the use of the median would be skewed
by the very high salaries. The median would likely provide a more accurate measure of the central
tendency of the salaries. Such circumstances are found where using the median to find the central
tendency prevents outliers in data that “skews” or shows extreme variations rather than showing
more symmetrical variations. The ALJs believe this is as accurate today as it was during the Docket
No. 38339 timeframe. They therefore find that the use of the median is the more appropriate
methodology for determining net salvage value.


       Remaining Life. Composite remaining life is the weighted average remaining life of the
property account for a group of all vintages. The average remaining life represents the future years
of service expected for the surviving property.


       There are numerous ways to calculate the remaining life (life parameter) of a group of assets
in a depreciation study. Examples include the interim retirement rate method and the retirement
(actuarial) rate method. The interim retirement rate method uses interim retirement curves to model
(predict) the retirement of individual assets within plant accounts. Alternatively, the retirement
(actuarial) rate method uses historical mortality data for a group of assets and compares that data to
various known patterns of industrial asset mortality rates (Iowa Curves). If the historical data
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creates a pattern of mortality that closely follows one of the Iowa Curves, then that Iowa Curve may
be used to approximate the remaining lives of that given group of assets in the future. Whether the
historical mortality data creates a pattern that closely follows a given Iowa Curve is determined
through plotting both sets of data (the historical mortality data and the Iowa Curve) on a graph and
quantifying the closeness of fit through statistical analysis and visual examination.


          Mr. Watson used multiple methods to calculate the remaining lives of assets, depending on
the asset. Generally, he used the retirement rate (actuarial) method.402 However, to calculate the
remaining life of production plant accounts, he used the interim retirement rate method.403 Ms.
Mathis disagreed with the use of the interim retirement rate method because the Commission has
rejected the application of interim retirement rates of production plant, as they are based on future
projection of retirements, for ETI and Central Power and Light Company in Docket Nos. 16705404
and 14965,405 respectively.


          ETI argues that the life span procedure, without the use of interim retirement curves, is
unrealistic in its assumption that all production plant assets are “depreciated (straight-line) for the
same number of periods and retire at the same time (the terminal retirement date).” Use of interim
retirements is an important refinement that adds accuracy to the determination of the depreciation
rates according to ETI. Mr. Watson offered the following explanation:


          Adding interim retirement curves to the procedure reflects the fact that some of the
          assets at a power plant will not survive to the end of the life of the facility and should
          be depreciated (straight-line) more quickly and retired earlier than the terminal life of
          the facility.406


402
      ETI Ex. 13 (Watson Direct) at 16.
403
      Staff Ex. 2 (Mathis Direct) at 14.
404
   Application of Entergy Gulf States, Inc., for Approval of its Transition to Competition to Competition Plan
and the Tariffs Implementing the Plan, and for the Authority to Reconcile Fuel Costs, to Set Revised Fuel
Factors, and to Recover a Surcharge for Under-recovered Fuel Costs, Docket No. 16705 (Oct. 14, 1998).
405
    Application of Central Power & Light Company for Authority to Change Rates, Docket No. 14965
(Oct. 16, 1997).
406
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1, at 7-8.
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ETI contends that this issue presents a unique situation where all the experts agree with the
theoretical soundness of Mr. Watson’s approach, but Mr. Pous and Ms. Mathis recommend its
rejection due to the existence of contrary Commission precedent. The impact of their position is a
$1,558,081 reduction to depreciation expense, based on December 31, 2010, plant balances.
Mr. Pous generally supports the use of interim retirements because “I think it’s right,”407 and he uses
the method in other jurisdictions, where it is a prevalent practice. Ms. Mathis “also appears to
recognize the theoretical soundness of utilizing interim retirements.”408 Even in Docket No. 16705,
the precedent cited by Mr. Pous and Ms. Mathis, the Staff depreciation witness agreed that the use of
interim retirements was appropriate, though not blessed by the Commission. ETI argues that use of
interim retirements reflects the undisputable fact that “generating units will have retirements of
depreciable property before the end of their lives.”409


          ETI is correct that neither Ms. Mathis nor Mr. Pous provide any reasoning behind the prior
Commission precedent. Moreover, it is also true that the Commission precedent is relatively old at
this point (dating back to the mid-1990s) and apparently has not been revisited in any recent cases.
ETI argues that the Commission has in at least one other case used interim retirements (Docket
No. 15195410), but provides little more than that comment to support the concept. It is true that in
concept, interim retirements are determined in much the same fashion as other elements of
depreciation analysis.       Primarily based on historical accounting data, the analyst identifies
characteristics in the history of the data upon which to base a reasoned assessment of retirements
going forward, which is similar to what occurs in determining asset lives or net salvage. Interim
retirement determinations are supported by their own Iowa Curves, just as is the analysis of plant
lives.


          Although the ALJs are persuaded by ETI’s arguments that the use of interim retirements may
be the more theoretically correct methodology to employ, Commission precedent clearly disfavors

407
      ETI Ex. 71 (Watson Rebuttal) at 71, citing Pous Deposition at 49, 51.
408
      Staff Ex. 2 (Mathis Direct) at 12-13.
409
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1, p. 8.
410
   Application of Texas Utilities Electric Company for the Reconciliation of Fuel Costs, Docket No. 15195
(Aug. 26, 1997).
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the use of interim retirements and the ALJs are reluctant to rule contrary to Commission precedent.
Accordingly, the ALJs find that the retirement (actuarial) rate method, rather than the interim
retirement method, should be used.


          2. Production Plant

                       (a) Lives

          Mr. Watson primarily used the life span method to calculate remaining lives of the
production plant accounts.411 The life span method estimates a production plant’s life based on
consultation with utility management, financial, and engineering staff.412 However, he used interim
retirement methodology to reduce the remaining lives determined by the life span method. Staff
does not dispute the remaining lives determined by the life span methodology, but does dispute the
use of interim retirements. For the reasons discussed in Section VII.C.1, ETI should not be allowed
to use the interim retirement methodology to adjust downward the remaining lives of its production
plant accounts.


          Cities witness Pous disputed only the remaining life determination for ETI’s Sabine Power
Plant Units 4 and 5, ETI’s largest and newest gas fired generating units. Mr. Pous recommended a
life span for Sabine Units 4 and 5 of 64 years based on assessment of the units, comparison to the
estimated life span of similar units owned by ETI as well as other gas fired generating units across
the country. ETI proposes a 60-year life for the two units. Mr. Pous noted that a “64-year life span
recommended for Sabine Units 4 and 5 is consistent with the life span proposed by the Company for
its Lewis Creek 1 generating unit. Lewis Creek Unit 1 is an older, smaller, and generally less
efficient generating unit than Sabine Units 4 and 5. Cities contend that there is no basis or logic for
assigning a shorter life span for a more capital-intensive asset that is newer, larger, and generally
more efficient.”413



411
      ETI Ex. 13 (Watson Direct) at 16.
412
      Staff Ex. 2 (Mathis Direct) at 14.
413
      Cities Ex. 5C (Pous Depreciation Study) at 9.
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          ETI witness Watson explained that he primarily relied on the determination of Company
personnel to arrive at the 60-year life for the Sabine Units. Although Cities attempted to cast doubt
on Mr. Watson’s determinations regarding the life of these units, it is clear that his determinations
are based on conversations with ETI various generation personnel and that those conversations
confirmed that based on evaluation of a variety of considerations, including age, operational role,
level of funding, unit condition, and operational risk, 60 years constitutes a reasonable threshold for
the expected life of Sabine Units 4 and 5. It is also clear that comparisons to Lewis Creek Unit 1 are
not appropriate. Lewis Creek Unit 1 has significant differences, which explain its longer life-span.
Unlike the Sabine Units, ETI is planning to spend in excess of $100 million to refurbish the Lewis
Creek critical equipment over the next three years to sustain operating reliability. ETI is not
performing similar refurbishment activities at Sabine.414


          The Sabine Units are projected to be “must-run” units. This means that these units are, for
the most part, deployed to operate whenever they are available for service. Mr. Pous compared these
units to EAI’s Lake Catherine Units 1 & 2,415 but ETI contends this is not a reasonable comparison.
EAI’s Lake Catherine Units 1 & 2 are not “must-run” units. They experience very infrequent
operation and are not projected to run much in the future. Other things being equal, according to
ETI, this would justify the longer 67-year life span assigned to these Arkansas units, because they
would not be experiencing the wear and tear of daily operation.416


          The explanations offered by ETI for the 60-year life of the Sabine Units 4 and 5 generating
facilities are convincing. It appears that Mr. Watson engaged knowledgeable people within ETI to
gather pertinent information and applied that information appropriately. The comparison to Lake
Creek units is not appropriate given the planned refurbishment of those units. Similarly, the
comparison to the Lake Catherine units also fails. A unit that does not carry the “must-run”
designation can easily be expected to perform longer than a unit, such as the Sabine Units, that



414
      ETI Ex. 51 (Garrison Rebuttal) at 3.
415
      Cities Ex. 5 (Pous Direct) at 7-8.
416
      ETI Ex. 51 (Garrison Rebuttal) at 3.
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carries the “must-run” designation. Accordingly, the ALJs find that ETI’s choice of a 60-year life
for the Sabine Units 4 and 5 is reasonable.


                       (b) Net Salvage Value

           In determining the net salvage attributable to production plant, ETI witness Watson started
with the negative 5 percent net salvage factor approved most recently for ETI in PUC Docket
No. 16705. This is a net salvage value that the Commission has adopted in a number of cases for
production plant.417 Mr. Watson testified that the net salvage calculation must reflect known
changes in the cost of retiring production plant since the net salvage factor was last set.
Accordingly, Mr. Watson’s study used the Handy-Whitman labor index to calculate the change in
labor costs applicable to removal activity for the years 1997 to 2010. Consideration of the increases
in labor costs over this 13-year period resulted in an increase in the cost of removal, and a
corresponding increase in the level of negative net salvage, from negative five percent to
negative 8.5 percent.418


           Both Staff witness Mathis and Cities witness Pous disagreed with ETI’s proposal for
production plant net salvage. Ms. Mathis proposed that the existing negative 5 percent net salvage
factor be retained. Ms. Mathis stated that Mr. Watson’s analysis is flawed for three reasons:


x     First, Mr. Watson did not calculate a gross salvage value for each plant. This is a
      necessary element of the fundamental net salvage rate calculation.419

x     Second, Mr. Watson unreasonably assumed that all steam production plants would be
      demolished at the end of their estimated remaining lives without any consideration of
      reuse of the unit after refurbishment, or mothballing the unit or selling the unit in the
      event of deregulation of the generating function of the utility.420




417
      Staff Ex. 2 (Mathis Direct) at 17.
418
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1, at 64.
419
      Staff Ex. 2 (Mathis Direct) at 16-17.
420
      Id. at 17.
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x     Third, Mr. Watson did not provide detailed plans for the actual demolition of each of its
      power plants. The Commission has consistently approved negative five percent net
      salvage rates for production plants if detailed plant-specific and reasonable demolition
      cost studies were not filed by the utility.421

            ETI responds that Staff’s recommendation fails to account for the fact that the
negative 5 percent benchmark is stale, having been established in a Commission proceeding 35 years
ago. Since that time, “labor costs have escalated by 267 percent with the rational expectation that
they will continue to increase at least with inflation.”422


            Cities witness Pous recommended moving from the current negative five percent net salvage
to a positive 5 percent net salvage; i.e., that it should be determined that the gross salvage from the
power plants will exceed the removal cost. Mr. Pous stated that he bases this claim on the ETI’s
actual experience over the past 45 years as well as current trends within the industry in the last
14 years. According to Mr. Pous, ETI has retired many units since 1965 and demolished or sold the
units and achieved a range of net salvage values from zero percent net salvage to
positive 180 percent.423 Other utilities in Texas and elsewhere have also experienced positive net
salvage levels.424 Mr. Pous testified that since 1998 over 1,000 generating units have been sold, and
in all instances resulted in positive net salvage.425 He also claims that his positive five percent
production net salvage is consistent with the Commission’s decision in the most recent SPS case,
Docket No. 32766, where Mr. Watson was hired by SPS as a depreciation witness and the
Commission ultimately approved a positive five percent net salvage.426 As ETI notes, however, the
SPS rate case was the result of settlement427 and is of little precedential value.




421
      Id.
422
      ETI Ex. 71 (Watson Rebuttal) at 17, 19.
423
      Cities Ex. 5 (Pous Direct) at 15.
424
      Cities Ex. 5C (Pous Depreciation Study) at 11; Cities Ex. 5 (Pous Direct) at 15-16.
425
      Cities Ex. 5C (Pous Depreciation Study) at 11.
426
      Cities Ex. 5 (Pous Direct) at 17.
427
      See ETI Ex. 71 (Watson Rebuttal) at 6.
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          ETI argues that Cities witness Pous appears to primarily base this claim on the fact that the
sale of utility plants in circumstances bearing no relationship to depreciation analysis has yielded
gains that Mr. Pous characterizes as “positive net salvage.” He uses as examples sales that form a
part of the restructuring of the Texas utility business to introduce retail competition. Ms. Mathis
also concluded, without elaboration, that ETI’s production plant net salvage analysis is flawed
because it does not consider the possibility that the unit could be sold as a consequence of
deregulation. Neither Ms. Mathis nor Mr. Pous, however, pointed to any instance in which the
Commission has adopted such an approach to determining net salvage.


          ETI contends that this argument should be rejected for a number of reasons. It argues that
although there is no precedent supporting Ms. Mathis’ and Mr. Pous’ approach, there is clear recent
precedent rejecting the inclusion of sales in depreciation analysis.428 The sales referenced by these
witnesses are unique and unpredictable events, as should be evident from the use of the restructuring
of the utility industry as an example of this type of activity. Indeed, at this time the Texas
Legislature has halted for the foreseeable future any ETI move to competition. For purposes of
depreciation analysis, net salvage is aimed at determining the salvage received at the end of the
plants’ useful lives. Mr. Pous’ analysis necessarily assumed that, due to the sale, the life of the
plants will be truncated. Yet he made no adjustment to production plant lives to account for the
effect of theoretical sales.429


          ETI also contends that Mr. Pous’ other examples of positive net salvage are equally
unavailing. Mr. Pous points to ETI’s retirement of Neches Station as an example of positive
salvage,430 but fails to mention that: (1) this outcome was uniquely the result of insurance proceeds
received by ETI after a boiler explosion; and (2) the proceeds flowed back to customers via means
other than depreciation rates.431 ETI contends that Mr. Pous’ claim that a contractor paid $1 million

428
   See Application of AEP Texas Central Co. for Authority to Change Rates, Docket No. 33309, FoF 107,
108, 112 (Mar. 4, 2008) (proceeds from sale of building properly removed from depreciation analysis as
non-recurring item).
429
      ETI Ex. 71 (Watson Rebuttal) at 5-7.
430
      Cities Ex. 5 (Pous Direct) at 14.
431
      ETI Ex. 46 (Considine Rebuttal) at 49-50.
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for the right to demolish a power plant, apparently based on unrecorded hearsay conversations, and
without any information from Mr. Pous regarding the facts and circumstances surrounding the
transaction, proves nothing.


          Finally, Mr. Pous stated that Mr. Watson’s adjustment to the net salvage rates is flawed
because it does not adequately reflect the increase in scrap metal prices in recent years. ETI
responds that although scrap metal prices have gone up recently, it is unknown what the prices will
be in the future, and these commodity prices have proven to be quite volatile and unpredictable.432
According to ETI, it is not reasonable to assume, as does Mr. Pous, that prices will stay indefinitely
at what is their historically highest level. ETI argues that Mr. Pous’ method is based on speculation
and broad, conclusory opinions regarding economic trends, as to which he makes no attempt to
actually arrive at a quantifiable analysis that yields his unprecedented positive net salvage
recommendation.433


          Mr. Pous’ testimony that net salvage value should be revised to reflect a value of
positive 5 percent is seriously flawed. First, pointing to a settled case as precedent carries no weight.
Second, attempting to draw conclusions from sales that were forced to comply with the regulatory
framework and apply those conclusions to an entity that is not subject to the same regulatory
framework is equally flawed. Finally, Mr. Pous attempted to use ETI’s own experience to support
his position ignores the fact that ETI’s experiences were driven by factors that were unique to ETI at
the time and circumstances involved; they do not support the more universal application urged by
Mr. Pous.


          Ms. Mathis’ analysis, in some respects, suffers from the same flaws as Mr. Pous’.
Nevertheless, some of her points carry more weight. The ALJs believe that Mr. Watson is correct
that labor costs have increased since the negative five percent net salvage value was first established
by the Commission. However, that is not the end of the story. Are there other factors that also have
changed in the corresponding time period? There is no evidence on this point, and that is the crux of

432
      ETI Ex. 71 (Watson Rebuttal) at 17-18.
433
      ETI Initial Brief at 103.
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the matter. As Ms. Mathis argues, there is only one way that all the changing values can be
evaluated; through the introduction of plant-specific demolition cost studies. Had studies of that
nature been provided, the parties would have been able to evaluate them and provide a supportable,
fully-vetted recommendation.           The ALJs recommend that the Commission find that a
negative 5 percent net salvage value for production plant is appropriate.


                      (c) Depreciation Reserve

          TIEC argues that $1.1 million of ETI’s requested $13 million increase in depreciation
expenses is related to ETI’s production plant assets.434 ETI has a $92,537,000 surplus in production
plant assets. A surplus depreciation reserve occurs when the theoretical reserve (the reserve that
would exist if the current proposed rates had been in place in the past) exceeds the per book
depreciation reserve. According to TIEC, this indicates that ETI customers have overpaid the value
of production plant assets.435 Since ETI has already over-recovered the value of the production plant
assets, there is no valid reason to seek any additional recovery. TIEC contends that ETI has not
shown why it needs to increase production depreciation rates at this time given that the production
depreciation reserve has a considerable surplus. Therefore, it argues, $1.1 million of the proposed
increase should be rejected.


          ETI rejects TIEC’s recommendation because it is clearly contrary to Commission policy and
precedent. According to ETI, the Commission has consistently adopted the remaining life, straight-
line method for determining depreciation rates.436 This method requires that the remaining life of
the asset be determined, and depreciation rates established to recover the asset’s remaining cost in
equal installments over that life. In this way, by the end of the life, the costs will be recovered.
Mr. Pollock’s approach ignores these principles, and seeks to look back in time to compare how the

434
   ETI Ex. 13A (Watson Workpapers) at Appendix B. This figure is derived by subtracting the expenses
from the existing production plant account from the proposed production plant account.
435
      TIEC Ex. 1 (Pollock Direct) at 36-37, Ex. JP-5.
436
    See Application of AEP Texas Central Co. for Authority to Change Rates, Docket No. 33309, PFD at
127-128 (Mar. 4, 2008); Application of CenterPoint Electric Delivery Company for Authority to Change
Rates; Docket No. 39339, PFD at 86 (Dec. 3, 2010); Application of Oncor Electric Delivery Company, LLC,
for Authority to Change Rates, Docket No. 35717, PFD at 153-154 (June 2, 2009).
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depreciation rates now proposed would have affected the recovery in the past. Those past
depreciation rates, however, were authorized for use by the Commission. ETI argues that
depreciation rates are at all times estimates, subject to adjustment using updated studies, and there is
no reason for adoption of Mr. Pollock’s alternative. Finally, the Commission expressly rejected
adjustment to the outcome of remaining life depreciation determinations based on differences
between theoretical and book depreciation reserves in CenterPoint Docket No. 38339.437


          The ALJs agree with TIEC that the Commission’s decision in Docket No. 38339 is not
four-square on point with this case. That is not sufficient, however, to overcome the arguments
advanced by ETI in favor of its position in the current case. The Commission has consistently used
the remaining life, straight-line methodology for determining depreciation rates, and that
methodology requires that the remaining life of the asset be determined, and depreciation rates
established to recover the asset’s remaining cost in equal installments over that life. Mr. Pollock’s
proposal ignores that consistently applied methodology. The ALJs recommend that the Commission
approve ETI’s recommended treatment of the production plant depreciation reserve.


          3. Transmission Plant

                       (a) Lives

          Mr. Watson’s study presents ETI’s life proposal for transmission Accounts 350.2 to 359, a
total of eight accounts.438 Neither Staff witness Mathis nor Cities witness Pous took issue with any
of the recommended lives for transmission plant accounts.439 Accordingly, the ALJs recommend
that the Commission adopt ETI’s proposed lives for these accounts.




437
      ETI Ex. 71 (Watson Rebuttal) at 75-77 (citing CenterPoint Docket No. 38839 PFD).
438
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 30-36.
439
      Staff Ex. 2A (Mathis Direct) at 21; Cities Ex. 5 (Pous Direct) at 28.
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                      (b) Net Salvage Value

          Staff disagrees with Mr. Watson’s recommendations for two of the eight transmission
accounts, and Mr. Pous disagrees regarding three of the accounts. The parties’ positions on
transmission net salvage values in dispute are set out below:


                           Transmission Account Net Salvage
                Account           Current         ETI                        Staff           Cities
                                 Net Salvage    Proposal                   Proposal         Proposal
                                    Value
352-Structures & Improvements        -5%         -10%                         -5%             -10%
353-Station Equipment                +5%         -20%                        -20%              0%
354-Towers & Fixtures                -5%         -20%                         -5%             -20%
355-Poles and Fixtures              -25%         -30%                        -30%             -15%
356-Overhead Conductors &           -20%         -30%                        -30%             -10%
Devices

                  (i) Account 352-Structures & Improvements

          Mr. Watson’s analysis of this account, and for all the accounts in his study, included the
examination of trends and bands for numerous years. For Account 352, he found the five-year and
ten-year moving averages for the years 2008-2010 particularly telling.440 A moving average is a
rolling average that updates each year to include the additional year as part of the average for the
longer period under study. Mr. Watson testified that his recommendation of negative 10 percent net
salvage is consistent (albeit less negative) with the five-year and ten-year moving averages for 2008,
which range from negative 16.31 percent to negative 16.80 percent. Although the moving averages
for 2009 and 2010 appear more positive, this was the result of a large, atypical gross salvage in
2009.441 Cities propose no change to Mr. Watson’s recommendation.


          Staff witness Mathis recommended a net salvage rate of negative five percent for
Account 352. This recommendation is based on analysis of historical salvage data for the period of

440
      ETI Ex. 71 (Watson Rebuttal) at 56.
441
   ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 65. The atypical gross salvage resulted from the sale of a
spare transformer, an asset whose cost is booked to an entirely different account. ETI Ex. 71 (Watson
Rebuttal) at 57. The atypical amount is shown at Appendix E-2 at 1 of Mr. Watson’s depreciation study.
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1984 through 2010. Specifically, the three-year moving average for the same period produces a net
salvage rate of negative 5.53 percent, which is very close to the currently approved net salvage rate
for this account. Moreover, an examination of the mean and median rolling band averages for
Account 352 shows a range of net salvage rates between positive 0.08 percent and
negative 6.83 percent.442 Thus, according to Ms. Mathis, the net salvage rate of negative 5 percent is
a reasonable estimate based on the available historical data.


            In response to Mr. Watson’s contention that the 2008 moving average is the most important,
Ms. Mathis pointed out that the 2009 five-year and ten-year moving averages feature
positive 16.66 percent and positive 4.45 percent net salvage rates, respectively. Moreover, the 2010
five-year and ten-year moving averages feature positive 25.13 percent and positive 6.75 percent net
salvage rates, respectively.443 Ms. Mathis stated that if it is a sound depreciation methodology to
select a net salvage rate based on recent five-year and ten-year moving averages, then the rate for
this account should be significantly greater than either Ms. Mathis’ or Mr. Watson’s
recommendation.444


             Although the moving averages cited by Ms. Mathis for 2009 and 2010 appear to belie the
arguments raised by Ms. Watson, the ALJs are persuaded that those are significantly influenced by
the atypical gross salvage resulting from the 2009 sale of a spare transformer, an asset whose cost is
booked to an entirely different account. If, as claimed by Mr. Watson, the sale was sufficiently
atypical, it would influence both 2009 and 2010 moving averages, making them unreliable.
Accordingly, the ALJs recommend that the Commission adopt ETI’s negative 10 percent net salvage
value for Account 352.




442
      Staff Ex. 2 (Mathis Direct) at 22, Appendix C at 1.
443
      Id.
444
   According to Ms. Mathis, if 2009’s moving averages are adopted, the net salvage ratio should be around
positive 4.45 percent or positive 16.66 percent. If 2010’s moving averages are adopted, the net salvage ratio
should be around positive 6.75 percent or positive 25.13 percent.
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                   (ii) Account 353-Station Equipment

            Similar to Account 352, a large atypical positive salvage amount in this account makes the
most recent moving average appear more positive than the history would otherwise suggest.445
Mr. Watson recommended setting net salvage at negative 20 percent, which he contended is a
reasonable middle ground between the values suggested by the five-year and ten-year moving
averages for transaction year 2010 (which show net salvage of negative 14.42 percent and
negative 20 percent, respectively).446 Ms. Mathis agreed with the Company’s proposal on this
account.


            Although Mr. Pous acknowledged that retention of the current Commission-approved
positive five percent net salvage is supported by ETI’s experience, he ultimately opted for a
recommendation that the net salvage value be reduced to zero percent. Mr. Pous noted that the
actual per book data for a five-year band and a ten-year band are a positive 117.04 percent and a
positive 31.95 percent, respectively.447 Mr. Pous stated that his analysis does not ignore the positive
net salvage recorded by ETI because of the sale of transmission investment, rather he testified that:


            the Company has reported five separate sales during the past 22 years, or about once
            every four years. Such activity cannot be considered an ‘unusual circumstance’ or an
            outlier, and should be taken into consideration as an event that may continue to occur
            in the future. In a proper evaluation phase of a depreciation study, recognition of
            some level of future sales is appropriate.448

Mr. Pous’ analysis also reflected that transformers, which contain large quantities of copper and
produce gross salvage when retired, comprise a significant level of investment in this account, but
were underreported in the five-year and ten-year band analyses.449 Mr. Pous stated that, given the
significant increase in the value of copper, the future proportionate retirement of transformers will
result in future net salvage values being less negative or more positive than the historical data.


445
      The atypical amount is shown at Appendix E-2, p. 1 of 10 of Mr. Watson’s depreciation study.
446
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 65.
447
      Cities Ex. 5C (Pous Depreciation Study) at 21, 23.
448
      Id.
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           ETI responds that Cities’ criticism that the per book data in Mr. Watson’s workpapers show
a large positive net salvage value for the five-year and ten-year bands is unfounded. According to
ETI, Mr. Watson’s workpapers clearly indicate that adjustments were required and made to the per
book data for unique transactions involving sales and storm activity. As to sales, the workpapers450
show that in the 26 years of data for Account 353, there were three occasions with very large sales
proceeds for the sale of substations. As to storm activities, the same workpapers show only one
occasion in 26 years where gross salvage amounts were recorded. ETI contends that these unique
events are properly excluded from net salvage analysis and Mr. Pous’ reliance on the per book data
to establish positive net salvage is erroneous. With respect to Mr. Pous’ concern’s relating to the
price of copper, ETI responds that Mr. Pous’ reliance on copper’s scrap value is pure speculation,
unsupported by any ETI-specific data regarding the amount of copper at issue, or any consideration
of the offsetting significant and increasing labor costs involved in the removal of large station
transformers.


           As explained by Mr. Watson, it appears to the ALJs that the adjustments made were, indeed,
required because of the unique nature of the events they reflected. The ALJs also find that
Mr. Pous’ concerns relating to the price of copper are speculative. Coupled with the fact that Staff
supports ETI’s proposed net salvage value, the ALJs recommend that the Commission approve
ETI’s recommended negative 20 percent net salvage value.


                   (iii)   Account 354-Towers and Fixtures

           Although there is limited experience available for this account, the five-year and ten-year
moving averages for transaction year 2010 show a substantial level of negative net salvage
(negative 299 percent and negative 233 percent, respectively). Taking into account the low level of




449
      Id. at 22.
450
   ETI Ex. 13A (Watson Direct) Workpaper on CD, “Entergy Net Salvage Transmission Distribution
General” Spreadsheet, “Data Adjustments” Tab, Account 353.
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retirement experience, Mr. Watson stated that he moderated the outcome by recommending moving
to negative 20 percent net salvage.451 Mr. Pous concurred in this recommendation.


           Ms. Mathis recommended a net salvage rate of negative 5 percent for Account 354.452 This
recommendation is based on Commission precedent due to the absence of reliable historical salvage
data.453 Although historical salvage data is available for the period of 1984 through 2010, this
account had a low level of retirement during this period.454 Because of the limited retirement
activity, Ms. Mathis stated that a reasonable net salvage rate cannot be calculated from the historical
salvage data.455          For example, annual net salvage rates range from approximately
negative 6,000 percent to approximately positive 31,253,400 percent.456 According to Ms. Mathis,
such divergent numbers are indicative of the low retirement activity within this account.


           The negative five percent net salvage value recommended by Ms. Mathis is the current
Commission-approved number. The ALJs find it difficult to draw any conclusions from the paucity
of historical data. Had there been additional historical data, it might have been possible to reach the
conclusion urged by Mr. Watson; however, there was not. The ALJs recommend that the
Commission adopt the negative five percent net salvage value recommended by Staff.


                   (iv) Account 355-Poles and Fixtures

           The Commission approved net salvage value for this account is a negative 25 percent.457
This account has shown negative salvage since the 1990s, and the most recent ten-year moving
averages show negative 33.84 percent net salvage. Although years 2009-2010 reflect positive
salvage values, Mr. Watson determined that these values were the product of differences in the

451
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 66.
452
      Staff Ex. 2 (Mathis Direct) at 23.
453
      Id. at 23.
454
      ETI Ex. 13 (Watson Direct) at DAW-1 at 66.
455
      Staff Ex. 2 (Mathis Direct) at 23.
456
      Id. at Appendix C at 2.
457
      Cities Ex. 5C (Pous Depreciation Study) at 23.
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timing of the recording of the various transactions associated with the asset retirement, rather than
reflecting an actual positive salvage amount.458 For example, Mr. Watson’s net salvage workpapers
show a significant level of positive salvage only for the years 2009-2010 in Account 355.459 This is
at odds with the remainder of the net salvage data shown in the workpapers, which is almost
exclusively negative net salvage.460 Accordingly, Mr. Watson gave less weight to the 2009 and
2010 values, but moderated his recommendation compared to the ten-year moving averages,
resulting in a recommended net salvage of negative 30 percent. Ms. Mathis concurred.


          Cities witness Pous disagreed with Mr. Watson’s analysis, claiming: (1) per book data from
the five-year and ten-year moving averages show positive net salvage amounts; (2) authoritative
depreciation treatises do not support Mr. Watson’s decision to adjust relocation-related transactions
out of the analysis;461 (3) no portion of relocation-related costs can be treated as removal unless that
treatment is prescribed by contract with the third-party; and (4) after the correction to his analysis,
Mr. Watson changed his methodology to arrive at a negative net salvage recommendation. Mr. Pous
recommended an increase in the net salvage values to a negative 15 percent based on the actual
historical data of ETI. Cities contend that Mr. Pous was conservative in his recommendation given
the trend in the data. The most recent five-year band of actual data yields a positive two percent net
salvage.462


          The ALJs agree that the debate regarding this account essentially boils down to whether
Mr. Watson’s adjustment to remove relocation expense associated with third-party reimbursement
from the analysis is appropriate. Although Mr. Pous claims that Mr. Watson’s approach is contrary

458
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1, p. 66.
459
    ETI Ex. 13A (Watson Workpapers CD), Adjusted Data Net Salvage Tab, account 355, lines 130-131,
columns I – S.
460
   ETI Ex. 13A (Watson Workpapers CD), Adjusted Data Net Salvage Tab, account 355, at lines 105 – 129,
columns I – AC. The 2005-2006 data in this workpaper show an obvious example of an accounting
adjustment timing difference, wherein the year 2005 shows a $1,867,532 removal cost (row 126, column G),
while the immediately following year 2006 shows a large negative removal adjustment of ($1,059,096),
(row 127, column G).
461
    Relocations involve the situation where the Company is reimbursed by a third party who desires the
relocation or replacement of the facilities in question.
462
      Cities Ex. 5C (Pous Depreciation Study) at 22-25.
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to authoritative guidance, ETI contends that he arrives at that conclusion only by disregarding the
guidance in question, as well as Commission precedent. ETI argues that the depreciation text in
question squarely supports Mr. Watson’s approach:


          A reimbursed retirement is one for which the company is fully compensated at the
          time of retirement …. Usually reimbursed retirements should not be included in
          analysis of property whose investment is recovered through depreciation accruals.463

          Mr. Watson explained at hearing that, in his experience, adjustments to remove relocation
expense are standard in depreciation analysis, and to do otherwise would result in a disproportionate
impact on reasonably expected ongoing net salvage, caused by a transaction (the relocation) that
constitutes a very small portion of the overall assets in question.464


          Mr. Pous stated that all third-party reimbursements for facility relocation performed by the
Company have to be deemed as salvage (thereby inflating the salvage portion of the net between
removal costs and salvage proceeds) unless a contract between ETI and a third-party explicitly says
otherwise. Mr. Watson’s approach, however, is squarely supported the Commission’s decision in
the recent Oncor case, Docket No. 35717, where it was held that these third-party “reimbursements
are prepayments for new property being installed.”465 The ALJs find that Mr. Pous’ argument is not
credible in light of Mr. Watson’s treatment of relocations in general. Since Mr. Watson properly
removed such relocation expense from the depreciation analysis altogether, those amounts correctly
have no impact on depreciation rates, regardless of how they are allocated between gross salvage
proceeds and the cost of installing new facilities.


          ETI’s evidence and argument support its request. Accordingly, the ALJs recommend that the
Commission approve a net salvage of negative 30 percent as proposed by Mr. Watson.




463
      ETI Ex. 71 (Watson Rebuttal) at 63 (quoting Depreciation Systems, Iowa State Press, 1994, at 16-17).
464
      Tr. at 405.
465
      ETI Ex. 71 (Watson Rebuttal) at 63.
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                   (v) 356-Overhead Conductors and Devices

           The Commission approved net salvage value for this account is a negative 20 percent.466
Much as was the case with Account 355, ETI argues that timing differences in reflecting accounting
adjustments made the more recent shorter data bands less representative of reasonably expected
future net salvage. Mr. Watson’s study determined that the longer ten-year moving average for
transaction year 2010 showed salvage of negative 33 percent, so Mr. Watson recommended moving
to negative 30 percent net salvage for this account.467 Staff witness Mathis adopted the same
negative net salvage value.


           Cities’ witness Pous recommended an increase to the net salvage value to a
negative 10 percent based on a review of the actual historical data. The actual five-year and ten-year
bands yield a positive one percent and a negative 31 percent. Mr. Pous argues that the trend in the
data could justify even a less negative value.


           As with Account 355, the ALJs find that ETI’s evidence and arguments support its request.
Accordingly, the ALJs recommend that the Commission approve a net salvage of
negative 30 percent as proposed by Mr. Watson.


           4. Distribution Plant

                      (a) Lives

           An asset’s useful life is used to determine the remaining life over which the cost will be
spread for recovery through depreciation expense.468 The Company’s depreciation study addresses
14 distribution accounts included between Accounts 360.2 and 373.2. According to ETI, the life
parameters in Mr. Watson’s study reflect standard depreciation analysis procedures, including
comparison to standard Iowa curves and actuarial analysis, along with the exercise of informed


466
      Cities Ex. 5C (Pous Depreciation Study) at 25.
467
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 66-67.
468
      Id. at 16.
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judgment.469 Multiple bands and trends were reviewed and, in general, Mr. Watson’s study
explained that the dispersion curve chosen for each account is based on examination of the various
“placement and experience bands”470 and the characteristics of the underlying asset in each account.
The dispersion curve is then chosen that best matches the actual data.471 Staff disagrees with
Mr. Watson’s life parameters for three accounts; Cities with five accounts. The parties’ various
recommendations on the accounts in dispute are shown below:


                                         Depreciation Plant Lives
       Account               Approved Life    ETI Proposal      Staff Proposal             Cities Proposal
361                         45 yrs. S2      65 yrs. R3         70 yrs. R3                 65 yrs. R3
364                         44 yrs. S1      38 yrs. R1.5       40 yrs. R1                 44 yrs. L1
365                         44 yrs. S1      39 yrs. R0.5       40 yrs. R0.5               42 yrs. S-0.5
367                         40 yrs. S1      35 yrs. R1.5       35 yrs. R1.5               45 yrs. S-0.5
368                         39 yrs. S0      29 yrs. L1         29 yrs. L1                 33 yrs. L0.5
369.1                       36 yrs. S4      26 yrs. L4         26 yrs. L4                 33 yrs. R4

                   (i) Account 361 – Structures and Improvements

          Mr. Watson’s study depicts the fit between the actual data in the account and the 65 R3 life
parameter that he proposed for this account.472 Mr. Pous agreed with this recommendation.
Ms. Mathis stated, however, that a life parameter of 70 R3 is a better visual fit for the 1960-2010
experience band.473

          Considering all the historical mortality data available for this account (the overall experience
band), the selected Iowa Curve produces a conformance index (CI) of 37.53.474 The CI is a measure




469
      Id. at Ex. DAW-1 at 37-54.
470
   Placement bands look at assets installed in various years and reveal the types of assets in the account over
time. Experience bands show accounting transactions associated with the assets over time and reveal trends
associated with operational changes and other events.
471
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 37-54.
472
      Id. at Ex. DAW-1 at 37.
473
      Staff Ex. 2 (Mathis Direct) at 25-26.
474
      Id. at 26, Table-5.
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of closeness of fit, and a higher CI value indicates a closer fit between the two sets of data that are
being compared.475

           Mr. Watson recommended a life parameter of 65 years based on comparing various slices
(bands) of this account’s mortality data to the 65 R3 Iowa Curve.476 However, Staff argues that
Mr. Watson’s recommended life parameter and Iowa Curve of 65-R3 produces a CI of only 23.61
when measured against the overall (1960 – 2010) experience band.477

           ETI responds that the flaw in Ms. Mathis’ position is that she only looks at one band. As the
average age of the investment is only 19.22 years, it is inadequate to look at only one band that
examines a 50-year period. When shorter bands are also factored in (1970-2010 and 1990-2010), the
Company’s proposal shows a significantly higher CI, which is indicative of a better fit to the actual
data.478

           The ALJs are persuaded that, in this instance, Ms. Mathis erred by limiting her review to a
single band, especially when that band is significantly longer than the average age of the investment
at issue. In this case, looking at multiple, shorter bands will give a clearer picture of the average life
of the investment at issue. Therefore, the ALJs recommend the Commission approve the 65 R3 life
parameter Mr. Watson proposes for this account.


                   (ii) Account 364 – Poles, Towers, and Fixtures

           Mr. Watson’s study results in his proposing a life parameter of 38 R1.5.479 He stated that the
current plant in service reflects a life (13.97 years on average) that is substantially shorter than his
recommendation, and all the bands examined reflect a shorter life than the currently approved
44 years. Mr. Watson testified that his recommendation balances these facts with the additional fact



475
      ETI Ex. 71 (Watson Rebuttal) at 24.
476
      ETI Ex. 13 (Watson Direct) at 18, Figure 1.
477
      Staff Ex. 2 (Mathis Direct) at 26, Table-5.
478
      ETI Ex. 71 (Watson Rebuttal) at 24.
479
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 41.
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that ETI is currently using Penta and CCA-treated poles (as opposed to creosote treated poles), for
which a longer life is expected.


            Ms. Mathis (40 R1) and Mr. Pous (44 L1) both proposed different life parameters than
Mr. Watson. Ms. Mathis stated that her proposed life parameter is a better visual and mathematical
fit for the single experience band (1959-2010) she considered.480 Mr. Watson responded to this
argument, stating that the mathematical computer fitting emphasized by Ms. Mathis is too limited an
approach, because there is too little information provided at the tail of the curve to rely on computer
fitting in this instance. Mr. Watson indicated that his proposed life parameter shows a better fit over
the full range of placement and experience bands applicable to this account.481


            Mr. Pous recommended that the expected service life remain at 44 years based on actuarial
analysis and advances made by the industry and ETI in treating and preserving poles.482 Mr. Pous
also noted that “absent identifiable and supportable specific problems, the industry is not
experiencing shorter lives for poles and neither should ETI.”483 He stated that selection of different
types of poles and different treatments by other utilities have their engineers expecting lives between
50 and 70 years.484 According to Mr. Pous, it is simply not realistic to believe or assume that ETI
would operate now or in the future in a manner that its poles would only last two-thirds the life
expectance being achieved by others.485 Mr. Watson responded that the increased life span urged by
Mr. Pous based on his general discussion of varieties of poles with longer lives is not verifiable, not
consistent with the Company-specific data or the specific experience of its distribution personnel,
and is plainly exaggerated.486




480
      Staff Ex. 2 (Mathis Direct) at 28-29.
481
      ETI Ex. 71 (Watson Rebuttal) at 29-31.
482
      Cities Ex. 5C (Pous Depreciation Study) at 35-36.
483
      Id. at 37.
484
      Id.
485
      Id. at 36.
486
      ETI Ex. 71 (Watson Rebuttal) at 28-29.
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          The ALJs reviewed the evidence and arguments of the parties with respect to this issue and
were most persuaded by the CIs that resulted from the recommendations of Staff and ETI.
Considering all the historical mortality data available for this account (the overall experience band),
Staff’s selected Iowa Curve produces a CI of 41.44, while ETI’s produces a CI of only 20.66 when
measured against the overall (1958 – 2010) experience band.487 The ALJs recommend that the
Commission adopt Staff’s proposal of 40 R1.


                   (iii)    Account 365 – Overhead Conductors and Devices

          The Commission approved average service life is 44 years.488 All parties propose a change
to this life parameter. Mr. Watson proposed a life parameter of 39 R0.5, Ms. Mathis proposes a life
parameter of 40 R0.5, and Mr. Pous proposed a life parameter of 42 S.-5.


          Mr. Watson noted that his analysis took into account the fact that the currently authorized life
is longer than the history would support, and that the young average age of the current plant in
service (12.15) points toward placing more weight on recent bands for life selection. He also noted
that ETI’s movement toward re-conductoring lines supports the conclusion that lives in this account
will be shorter.


          Ms. Mathis indicated that her recommendation is based on comparing the account’s historical
mortality data for the period of 1958 through 2010 to the 40 R0.5 Iowa Curve.489 Considering all the
historical mortality data available for this account (the overall experience band), the selected Iowa
Curve produces a CI of 29.63.490 Mr. Watson countered that Ms. Mathis used the wrong curve to
represent the Company’s proposal in her calculations. He stated that when her analysis is corrected




487
      Staff Ex. 2 (Mathis Direct) at 29, Table-6.
488
      Cities Ex. 5C (Pous Depreciation Study) at 38.
489
      Staff Ex. 2 (Mathis Direct) at 30.
490
      Id. at 31, Table-7.
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to make the proper comparison, ETI’s proposal has a higher CI (and thus a better fit) across all
experience bands save one.491


          Mr. Pous testified that his life parameter best matches the actuarial analysis taking into
account the unusually high level of retirement activity recorded in the first 0.5 year of age. As
Mr. Pous noted, “the highest retirement ratio for this investment in the first 23 years occurred at age
0.5 years, for brand new assets. While such events can and have occurred associated with utility
plant, it is not the type of event that is reasonably expected to repeat itself in future periods as
different equipment it purchases if it was an equipment problem, or different installation processes
are employed if the early retirement were due to installation issues.”492 Mr. Pous criticized
Mr. Watson’s recommendation on several grounds: (1) it is not consistent with expected lives
reported by ETI personnel; (2) it did not account for anomalies and/or unusual activity in the
retirement data; (3) the major re-conductoring activity shown in the account should not be expected
to continue; and (4) the life-curve combination chosen by Mr. Watson is not long enough to match
the actual data.493


          Mr. Watson took issue with Mr. Pous. He stated that Mr. Pous simply misread the data
Mr. Watson argued that Exhibit DAW-R-1 to his rebuttal testimony shows that retirements are
decreasing.494 Mr. Watson believes that his proposed life parameter is a better fit to the actual data.
The very small amount of plant that may not last until the tail of the curve used by Mr. Watson does
not alter this conclusion.495 Finally, ETI argues that Mr. Pous provides no persuasive basis for
second guessing the opinion of Company personnel regarding re-conductoring.


          The ALJs are persuaded by ETI’s evidence and argument. It does appear that Ms. Mathis
used the wrong curve in her calculations. If corrected, Mr. Watson’s proposal renders the higher CI.


491
      ETI Ex. 71 (Watson Rebuttal) at 36.
492
      Cities Ex. 5C (Pous Depreciation Study) at 38-39.
493
      Id. at 38-41.
494
      ETI Ex.71 (Watson Rebuttal) at 32-33.
495
      Id. at 32, 33-35.
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Mr. Pous’ arguments fair no better. To the ALJs’ eye, Mr. Pous did misread the data, and the
conclusions drawn by Mr. Pous are simply inaccurate. The ALJs recommend that the Commission
adopt ETI’s proposed life parameter of 39 R0.5.


                  (iv) Account 367 – Underground Conductors and Devices

          The Commission approved average service life is 40 years.496 Mr. Watson’s life parameter
for this account (35 R1.5) is based on his review of the various placement and experience bands, as
well as the characteristics and longevity of the conductors in place in the ETI system and the
retirement patterns that are unique to underground conductor performance and the locations where it
is buried.497 Ms. Mathis agreed with Mr. Watson on this account. Cities propose a significantly
longer life (45 S-0.5). Mr. Pous stated that Mr. Watson’s and Ms. Mathis’ recommendations do not
account for the increased durability of newer types of conductor, and that the actuarial analysis
should focus on more recent data that he believes is more consistent with the newer conductors.498


          Mr. Watson testified that Mr. Pous’ recommendation should be rejected for a variety of
reasons. The Southern California Edison-based opinions regarding longer life for the conductor,
relied on by Mr. Pous, relate to plant installed less than ten years ago. Therefore, based on his own
theory, much of the investment in question in this account is still the older, shorter-lived variety, and
his recommendations are premature. Moreover, Mr. Watson’s plotting of the dispersion curves
show that his is a better fit than that of Mr. Pous. In this instance, Mr. Pous’ analysis, relying only
on the shortest band, failed to pick up the older investment that constitutes almost 80 percent of the
surviving investment.499


          It appears that Mr. Pous, in relying on the shortest band, did fail to take into account
investment that comprises almost 80 percent of the surviving investment in this account. That is a
significant flaw in his analysis. Similarly, his reliance on the Southern California Edison-based

496
      Cities Ex. 5C (Pous Depreciation Study) at 41.
497
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1, p. 45.
498
      Cities Ex. 5C (Pous Depreciation Study) at 41-44.
499
      ETI Ex. 71 (Watson Rebuttal) at 40.
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opinions relate to newer plant, which again calls his analysis into question in the present
circumstances. The ALJs recommend that the Commission approve ETI’s recommended service life
of 35 R1.5.


                   (v) Account 368 – Line Transformers

           The Commission approved anticipated service life is 39 years.500 Mr. Watson proposed a
service life of 29 L1,501 with which Ms. Mathis agreed. Mr. Watson stated that this is consistent
with the data showing decreasing lives for these assets, the expected lives per Company personnel,
and the fact that transformers are junked or sold rather than repaired.502


           Mr. Pous recommended that the expected service life be decreased to 33 years, representing a
15 percent reduction in the anticipated service life. Mr. Pous stated that his analysis is based on
actuarial analyses and the Company’s addition of approximately $80 million of pad mounted
transformers since the last case, when the Commission approved a 39-year anticipated average
service life. According to Mr. Pous, ETI personnel have stated that pole mounted transformers have
a life of between 25 and 35 years. However, pad mounted transformers are expected to last up to
40 years by the same Company personnel. Given the sizable investment since the last case in the
pad mounted transformers with a longer expected service life, a decrease in the anticipated service
life of greater than 15 percent is not warranted, according to Mr. Pous. Moreover, Mr. Pous stated
his analysis uncovered abnormally high retirement ratios in the 21.5 to 22.5 year age brackets
indicative of one-time events such as the ice storm or changes in accounting systems. As such,
Mr. Pous performed his curve fitting analysis recognizing the unusually high retirement activity
between years 21.5 and 22.5 rather than emphasizing such unusual activity as Mr. Watson did for his
proposal to reduce service life by 26 percent.503




500
      Cities Ex. 5C (Pous Depreciation Study) at 44.
501
      ETI Ex. 13 (Watson Direct) at Ex DAW-1 at 50.
502
      Id. at 47.
503
      Cities Ex. 5C (Pous Depreciation Study) at 45.
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            Mr. Watson recommended a decline in average service life from a 39-year anticipated service
life to a 29-year anticipated service life citing the high occurrence of lightning in the ETI service
area.504 However, Mr. Pous noted that the effects of lightning in ETI’s service area would have been
present in ETI’s last base rate case when a 39-year anticipated service life was approved by the
Commission. Both Mr. Watson and Mr. Pous recognized that the pad mounted transformers are not
subject to the same forces of retirement like weather, lightning, and animal disturbances.505
However, Mr. Watson did not realistically factor ETI’s relative increased investment in pad mounted
transformers into his analysis. Moreover, when performing his curve fitting analysis, Mr. Watson
neither analyzed nor adjusted for the abnormal unusual retirement ratios between years 21.5 and
22.5.506 Instead, Mr. Watson attempted to select a life analysis that anticipates a high level of
retirement within that time period in the future.507 Cities argue that, by failing to recognize the
sizable new investment in pad mounted transformers and failing to consider the unusual retirement
ratios, Mr. Watson proposed an average service life that is lower than the bottom end of the range of
life estimates of Company personnel for pad mounted transformers. Moreover, Mr. Watson’s
proposal does not even reach the midpoint of life estimates expected by Company personnel for pole
mounted transformers.


            The arguments and evidence advanced by Cities witness Pous are persuasive to the ALJs.
Mr. Watson’s contention regarding the occurrences of lightening in the ETI service area was equally
applicable at the time the existing approved rate was set, and is, therefore, of little value in this
proceeding. Further, Mr. Watson’s failure to analyze the abnormal retirement ratios between years
21.5 and 22.5 also argues against his analysis. The ALJs recommend that the Commission adopt
Mr. Pous’ proposed life of 33 L0.5.




504
      ETI Ex. 13 (Watson Direct) at Ex DAW-1 at 50.
505
      Id.
506
      Cities Ex. 5C (Pous Depreciation Study) at 47.
507
      ETI Ex. 13 (Watson Direct) at Ex DAW-1 at 50-51.
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                      (vi) Account 369.1 – Overhead Services

          The Commission previously approved anticipated service life for this account is 36 years.508
Mr. Watson’s analysis of this account shows that overhead assets have retired earlier and have been
replaced more frequently than is consistent with the existing 36 S4 life. The average age of current
investment is 10.12 years. Consistent with this data and his review of various curves and placement
and experience bands, he recommended shortening the life to 26 L4. Ms. Mathis agrees with this
proposal.509


          Mr. Pous recommended that the expected service life be shortened to 33 years based on the
lack of Company historical data and based on comparative utility experience including recent studies
by Mr. Watson, where he proposed significantly longer average service lives. Mr. Pous testified that
an evaluation of the actual data casts serious doubt about the reliability of the data for depreciation
purposes. ETI does not have any records of services in this subaccount surviving past 1978.
Mr. Pous stated that his recommended 33-year life expectancy for this sub-account is still far shorter
than industry expectations, but is consistent with the depreciation study recently conducted for
EGSL where the depreciation expert hired by EGSL recommended a 33-year life.510


          ETI argues that Mr. Pous apparently made no attempt to perform any curve fitting regarding
this account, as none appears in his study; in the absence of performing this essential analysis, he
settles for again casting doubt on the reliability of Company accounting data. ETI contends that, in
reality, Mr. Pous appears to present no recommendation for this account based on evaluation of any
of the accounting data that actually depicts the past and current characteristics of the assets.511




508
      Cities Ex. 5C (Pous Depreciation Study) at 48.
509
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 49.
510
      Cities Ex. 5C (Pous Depreciation Study) at 48-49.
511
      Id. at 48-50.
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          ETI argues that its recommended life is clearly supported by the Company-specific data,
graphically depicted in Mr. Watson’s rebuttal testimony, while Mr. Pous’ suggested life parameter is
not even close, and is based on unsupported speculation.512


          Although the evidence on this issue is sparse, the ALJs ultimately are persuaded that ETI’s
(and Staff’s) position is more reasonable. Accordingly, the ALJs recommend the Commission adopt
ETI’s proposed 26 L4 life span.


                      (b) Net Salvage Value

          Staff disagrees with Mr. Watson’s recommendations for five of the distribution accounts, and
Mr. Pous disagrees regarding two of the accounts. The parties’ positions on distribution net salvage
values in dispute are set out immediately below:


                                  Distribution Plant Net Salvage
       Account          Approved Rate     ETI Proposal      Staff Proposal          Cities Proposal
 361                              -5%               -10%               -5%                     -10%
 362                             +15%               -20%              -10%                       0%
 365                             +10%                -7%               -7%                       0%
 368                               0%                 0%               -5%                       0%
 369.1                           -10%                -5%              -10%                      -5%
 369.2                           -10%                -5%              -10%                      -5%

                  (i) Account 361 – Structures and Improvements

          The existing net salvage value for this account is negative five percent, which is the value
proposed by Staff. Mr. Watson and Mr. Pous, on the other hand, proposed a salvage value of
negative 10 percent.


          Mr. Watson’s recommendation is based on the most recent five-year and ten-year net salvage
ratios, which are negative 9.70 percent and negative 36.70 percent, respectively. Ms. Mathis’
recommendation is based on analysis of historical salvage data for the period of 1984 through 2010.
Specifically, the two-year moving average median for the same period produces a net salvage rate of

512
      ETI Ex. 71 (Watson Rebuttal) at 46-48.
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negative 5.87 percent, which is very close to the currently approved net salvage rate for this
account.513 Moreover, the one-year, three-year, four-year, five-year, six-year, and seven-year
moving average medians of negative 6.95 percent, negative 5.11 percent, negative 3.64 percent,
negative 1.90 percent, negative 4.57 percent, and negative 7.24 percent, respectively, support this
recommendation.          Additionally, this account contains a few significant outliers, such as
negative 655.91 percent in 2002 and negative 322.55 percent in 2005.514 Ms. Mathis’ use of the
median average eliminates the skewing effect of these outlying values.


          As discussed in Section VII.C.1, the use of the median is the most appropriate methodology.
For this reason, the ALJs recommend the Commission approve Staff’s proposed negative 5 percent
net salvage value.


                   (ii) Account 362 – Station Equipment

          The existing net salvage value of this account is positive 15 percent. Mr. Watson proposed
that it be changed to negative 20 percent, Staff proposes it be changed to negative 10 percent, and
Cities propose it be changed to zero.


          Mr. Watson’s study shows that the most recent five-year and ten-year net salvage ratios are
negative 22.10 percent and negative 43.55 percent, respectively.         He recommended negative
20 percent net salvage based on the Company’s experience.515


          Ms. Mathis’ recommendation is based on analysis of historical salvage data for the period of
1984 through 2010. Specifically, the recommendation is supported by the two-year moving average
median for the same period of negative 12.23 percent.516 Moreover, the one-year, three-year,
five-year, six-year, seven-year, and eight-year moving average medians of negative 11.07 percent,



513
      Staff Ex. 2 (Mathis Direct) at 27.
514
      Id. at Appendix C at 4.
515
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 68.
516
      Staff Ex. 2 (Mathis Direct) at 27.
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negative 14.16 percent, negative 7.62 percent, negative 8.19 percent, negative 11.75 percent, and
negative 14.15 percent, respectively, support her recommendation.517


           Mr. Pous’ recommendation is based on what he characterizes as the Company’s actual,
unadjusted, experience; recognition of the type of investment in the account; recognition of
significant value of scrap copper; investigation of retirement mix compared to investment mix over
the past ten years; and recognition of industry values.518 According to Mr. Pous, given the
significant increase in the value of copper, the retirement of a transformer could be expected to
significantly influence the net salvage value for this account.


           Mr. Pous’ recommendation is the outlier among the three before the ALJs, and the ALJs are
not convinced that the reasons put forth by Mr. Pous in support of his position are sufficient to carry
the day. The real argument here is between ETI and Staff, which centers on the use of the median
(Staff) and the mean (ETI). As discussed in Section VII.C.1, the use of the median is the most
appropriate methodology. For this reason, the ALJs recommend the Commission approve Staff’s
proposed negative 10 percent net salvage value.


                   (iii)    Account 365 – Overhead Conductors and Devices

           The current net salvage value for this account is positive 10 percent.519 ETI and Staff
recommend changing it to negative seven percent, and Cities recommend changing it to zero.


           Mr. Pous recommended a reduction in the current net salvage values to zero based on review
of the actual historical data and the relative mix of the investment recorded in this account.
Mr. Pous noted that $40 million of investment recorded in this account is associated with clearing
rights of way, which will not likely be retired or incur cost of removal or gross salvage. Another $40




517
      Id. at Appendix C at 4-5.
518
      Cities Ex. 5C (Pous Depreciation Study) at 26.
519
      Id. at 28.
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million is associated with investment in copper conductors, which has escalated in demand in recent
years and should result in positive net salvage.520


          Mr. Watson corrected his analysis and recognized that timing differences between the
recording of accounting adjustments related to net salvage (i.e., salvage and removal costs for a
particular transaction were not recorded at the same time) made one of the recent years less
representative of reasonably expected ongoing net salvage levels. He focused, therefore, on longer
period averages and recommends negative seven percent net salvage consistent with the most recent
ten-year ratios.521 Mr. Watson explained that his adjustments removed relocation activity altogether
from this account because it is not characteristic of the vast majority of retirements and because, if
the adjustment is not made, it will shorten and skew the life analysis. Further, Mr. Watson stated
that Mr. Pous’ claims regarding the impact of copper prices ignore those prices’ future volatility and
are not supported by any analysis or quantification specific to these accounts. Mr. Watson indicated
that his recommendations are based on the most clear and reliable source – Company-specific
accounting data – not “selective comparisons of industry norms,” as alleged by Mr. Pous.522


          The ALJs find Mr. Watson’s explanations of the rationale behind his analysis to be both
credible and convincing. Accordingly, the ALJs recommend the Commission adopt ETI’s requested
negative 7 percent net salvage value.


                      (iv) Account 368 – Line Transformers

          The existing net salvage value for this account is zero, which both Mr. Watson and Mr. Pous
recommended be retained. Ms. Mathis, on the other hand, argued that the net salvage value should
be changed to negative five percent.


          The argument here is whether the median or the mean best represents the appropriate net
salvage value. ETI argues for the mean, and Staff argues for the median. As discussed in

520
      Id. at 28-29.
521
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 69.
522
      ETI Ex. 71 (Watson Rebuttal) at 68-69.
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Section VII.C.1, the use of the median is the most appropriate methodology. For this reason, the
ALJs recommend the Commission approve Staff’s proposed negative five percent net salvage value.


                   (v) Account 369.1 – Overhead Services

          The existing net salvage value for this account is negative 10 percent, which Staff
recommends be retained. Mr. Watson and Mr. Pous argue in favor of a change to negative 5 percent
net salvage value.


          The argument here is whether the median or the mean best represents the appropriate net
salvage value. ETI argues for the mean, and Staff argues for the median. As discussed in
Section VII.C.1, the use of the median is the most appropriate methodology. For this reason, the
ALJs recommend the Commission approve Staff’s proposed negative 10 percent net salvage value.


                   (vi) Account 369.2 – Underground Services

          ETI began specifically charging salvage and removal cost to this account just in the last two
years, producing a five-year net salvage ratio of negative 15.75 percent. Mr. Watson recommended
moving from the current negative 10 percent to negative five percent net salvage.523 Mr. Pous
agreed. Because of the limited available data, Ms. Mathis recommended retaining the existing
negative 10 percent net salvage.524


          The ALJs agree with Staff that because of the limited retirement activity, a reasonable net
salvage rate cannot be calculated from the historical salvage data. Accordingly, the ALJs
recommend the Commission adopt the negative 10 percent net salvage value proposed by Staff.


          5. General Plant

          General plant includes some accounts that are subject to depreciation, and some that are
subject to amortization. ETI proposes to adopt “Vintage Group Amortization,” consistent with

523
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 70.
524
      Staff Ex. 2 (Mathis Direct) at 34.
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FERC Rule AR-15 for Accounts 391-397.1 and Account 398. This approach, approved by both the
FERC and the Commission (Docket No. 38339), does not affect the annual level of expense, but
provides for timely retirement of assets and simplifies accounting for general property.525
Ms. Mathis concurred in the Company’s proposal to adopt Vintage Group Amortization and with its
recommendations for lives, amortization periods, and net salvage.526


          The increase in expense for general plant proposed by ETI is due to the need to reduce the
deficit in the general plant reserve caused by inadequate account level rates in the past.527 This is a
matter of debate among the parties, as discussed in more detail below.


                       (a) Account 390 – Structures and Improvements (Life Parameter)

          Based on his analysis of the data in comparison to various potential dispersion curves,
Mr. Watson recommended an increase in the life of this account to 45 R2.528 Ms. Mathis agreed
with this life. Mr. Pous proposed a significantly longer life (54 S0.5) and claimed that Mr. Watson
did not adequately investigate the data and investments in this account. Mr. Pous concluded that
“superstructures and roadways” are a significant element in the account which can be expected to
have a long life.529


          ETI contends that Mr. Pous’ analysis is incorrect. First, as confirmed by his workpapers,
Mr. Watson conducted an analysis of five bands, not a single band as alleged by Mr. Pous.
Furthermore, Mr. Pous’ argument regarding long lives, based on the idea that the investment dates
back to 1927, is contrary to the actual data showing a minute amount of old investment (0.02 percent
of the account) dating back only to 1939. The average age of investment in the account, however, is




525
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 2-3.
526
      Staff Ex. 2 (Mathis Direct) at 35-37.
527
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 2-3.
528
      Id. at Ex. DAW-1 at 56.
529
      Cities Ex. 5C (Pous Depreciation Study) at 51.
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only 15.87 years. Mr. Watson explained that the actual data shows no investment has achieved a life
of 85 years, as alleged by Cities.530


          The ALJs believe that the actuarial analysis and curve fitting shown in Mr. Watson’s direct
and rebuttal testimony demonstrate a more reasonable approach, as recognized by Staff witness
Mathis.      Therefore, the ALJs recommend the Commission adopt the 45 R2 life parameter
recommended by ETI.


                      (b) Account 390 – Structures and Improvements (Net Salvage Value)

          Account 390 is a depreciable account for structures and improvements. Though the current
authorized net salvage is zero, Mr. Watson recommended a negative five percent net salvage value,
and Staff agrees with this recommendation. Mr. Pous recommended a positive 15 percent net
salvage value.


          Mr. Watson based his recommendation on the most recent five-year and ten-year ratios,
which are negative 1.51 percent and negative 34.27 percent.531 Mr. Pous disagreed, arguing that:
(1) Mr. Watson’s data adjustments present an incorrect picture of the salvage history; and
(2) Mr. Watson failed to account for the difference in net salvage values between the retirements of
leaseholds, versus Company-owned facilities, which should not produce negative salvage.532


          According to ETI, Mr. Pous’ argument that retirement and sales of buildings will result in
positive net salvage is not backed up by the Company-specific data for this account. Such data
shows that negative net salvage has occurred in every period of the most recent ten-year moving
average.      Averages of six years or longer range from negative 4.56 percent to negative
34.27 percent.533 ETI also argues that Mr. Pous’ attempt to use sales of facilities as an element of
depreciation analysis is contrary to Commission precedent regarding building sales ’and that his

530
      ETI Ex. 71 (Watson Rebuttal) at 49.
531
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 73.
532
      Cities Ex. 5C (Pous Depreciation Study) at 31.
533
      ETI Ex. 71 (Watson Rebuttal) at 73-74.
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opinion is contrary to the facts that such sales are unique circumstances that do not reasonably
represent the ongoing year-to-year retirement activity that should form the basis of depreciation
analysis.


          The ALJs find that Mr. Pous’ arguments are not supported by the facts and that Mr. Watson’s
explanations are the more credible. Accordingly, the ALJs recommend the Commission adopt ETI’s
proposed negative five percent net salvage value for this account.


                       (c) General Plant Reserve Deficiency

          A $21.3 million deficit has developed over time in the reserve for the accounts that ETI
proposes should be converted to General Plant Amortization. This deficit, or under-recovery, has
occurred because assets have been retired more quickly than can be addressed by the existing
amortization rate. ETI, therefore, proposes a $2.1 million annual expense level to recover the deficit
over ten years.534 Ms. Mathis recommended that the amortization of the reserve deficiency be
rejected and that the deficit be recovered through application of the remaining life method to the
individual accounts where the deficit occurred.535


          ETI argues that although Ms. Mathis’ recommendation could theoretically allow recovery,
her calculation of the amortization for the accounts that created the deficit is erroneous and
insufficient to carry out her proposed concept for recovery. During her cross examination,
Ms. Mathis agreed that she had intended to take the elements of the remaining life calculation
method exclusively from Mr. Watson’s depreciation study. 536 ETI contends that she failed to pull
the correct values from Mr. Watson’s study and her numbers did not match the corresponding entries
from Mr. Watson’s study.537 For example, Ms. Mathis affirmed that her remaining life calculations
were intended to allow recovery of the remaining investment in general plant account 391.2. The



534
      ETI Ex. 13 (Watson Direct) at Ex. DAW-2 at 2, App. A-2 at 1-2.
535
      Staff Ex. 2 (Mathis Direct) at 38.
536
      Tr. at 1752-1753.
537
      Tr. at 1746-1759.
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remaining investment she provided for was $10.9 million of an original cost of $21.7 million.538 The
actual remaining investment in the account, however, as shown in the data she purported to rely on,
was a credit balance of negative $4.4 million, meaning that not only the original cost, but
$4.4 million additional investment remained unrecovered.539 Ms. Mathis had no explanation for the
difference. In fact, it appears that she erroneously substituted the theoretical reserve for the account
in Mr. Watson’s study ($10.789 million) as the actual book reserve, resulting in an erroneous
calculation of the amount yet to be recovered.540 Mr. Watson’s rebuttal points out the errors in the
calculation and provides an exhibit to properly reflect the remaining life approach that Ms. Mathis
intended.541


          However, Mr. Watson’s rebuttal also explained the reasons that the Company’s approach is
better. By using a ten-year amortization period for the deficit, ETI lowers the annual amount of the
expense in rates to $2.1 million. Once Ms. Mathis’ calculation is corrected, because the remaining
lives through which the asset value is recovered are so short, ’her remaining life approach increases
the annual expense of amortization to $5.8 million. Given the significant level of expense involved,
ETI personnel had asked Mr. Watson to moderate the remaining life approach in this instance by
using a ten-year amortization period that was consistent with the approach used by another affiliate
within the Entergy system. Moreover, although Ms. Mathis purports to rely on the Commission’s
decision in Docket No. 38339 in support of her proposal, that case includes no discussion of
rejecting the proposal on general plant that Mr. Watson makes here.542


          The ALJs have reviewed the evidence cited by both parties and the testimony offered in
support of their respective positions. It is clear to the ALJs that Ms. Mathis inadvertently did exactly
what ETI alleges – she got numbers confused and, in so doing, confused her analysis. The ALJs find



538
      Tr. at 1754; Staff Ex. 2 (Mathis Direct) at Ex. JLM-2 at 4.
539
      Tr. at 1755.
540
      Tr. at 1759-1761.
541
      ETI Ex. 71 (Watson Rebuttal) at 84, Ex. DAW-R-5.
542
      Id. at 80-81.
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that ETI’s proposed $2.1 million annual expense level to recover the deficit over ten years be
approved by the Commission.


                       (d) Amortization Period for Account 391.2 – Computer Equipment

          Mr. Pous challenged the amortization period for this account, contending, contrary to Staff
and Mr. Watson, that the Company’s proposal to amortize general plant using “Vintage Group
Amortization” is not consistent with FERC pronouncement AR-15. ETI argues that Mr. Pous’
critique is wrong because the five-year life of which Mr. Pous complains is based on standard life
analysis. The life has nothing to do with AR-15, which does not determine such matters.
Mr. Watson’s study clearly explains that he based the life parameter on standard actuarial
analysis.543


          According to ETI, Mr. Pous’ own recommendation points out the fallacy of his arguments
about AR-15. He recommended a one-year increase in the amortization, which does not match the
previous period of depreciation for this account, or the previous depreciation rate, despite that being
the supposed flaw in Mr. Watson’s approach.544 Mr. Watson explained that the use of AR-15 does
not involve any independent tinkering with the life of the asset account because the AR-15 process
“provides for the amortization of general plant over the same life as recommended,” based on
standard life analysis, which Mr. Watson’s study recognized.545


          The ALJs are persuaded by ETI’s arguments on this point. FERC pronouncement AR-15
requires amortization over the same life as recommended based on standard life analysis.
Mr. Watson’s study employed standard life analysis to ascertain the recommended five-year life.
The ALJs therefore recommend the Commission adopt the five-year life proposed by ETI.




543
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 58.
544
      Cities Ex. 5 (Pous Direct) at 36.
545
      ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 2.
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           6. Fully Accrued Depreciation

           Mr. Pous claimed that the Company has failed to conform its Commission-authorized
depreciation rates when it stops accruing depreciation on accounts and sub-accounts that are fully
accrued. He testified that the Company must continue to depreciate such accounts, despite the fact
that this policy would mandate that the Company intentionally create negative depreciation amounts
that do not relate to the existence of any depreciable asset still in existence. Mr. Pous testified that
neither standard depreciation definitions nor GAAP or National Association of Regulatory Utility
Commissioners (NARUC) depreciation guidance support the Company’s action.546 The impact of
Mr. Pous’ recommendation is to impute an additional $6,447,731 depreciation amount to reduce rate
base and amortize that credit over four years, with an associated revenue requirement reduction of
$1,611,933.547


           ETI argues that Mr. Pous pointed to no instance in which his theory has been adopted by the
Commission, or any other regulatory body. Other regulators within the Entergy system have
rejected his position.548 The RRC, which sets gas utility rates under essentially the same regulatory
framework as PURA, has rejected Mr. Pous’ position on three separate occasions.549 ETI contends
that Mr. Pous’ suggestion violates GAAP, which requires that once an asset’s service value (original
cost less net salvage) has been fully amortized through the application of the most recently approved
depreciation rates, there is no further service value to be recognized. This has been ETI’s practice as
long as ETI regulatory accounting witness Considine has been aware. Furthermore, ETI suspends
depreciation only so long as the account is fully amortized. Once additional activity hits the
account, depreciation will begin again under the Company’s automated systems.550


           ETI also argues that Mr. Pous’ retroactive approach is unreasonably selective. He would
reach back into recoveries under existing rates to reclaim revenues associated with the depreciation

546
      Cities Ex. 5 (Pous Direct) at 39-45.
547
      Id. at 45.
548
      ETI Ex. 46 (Considine Rebuttal) at 45-46.
549
      ETI Ex. 71 (Watson Rebuttal) at 81, n. 61; ETI Ex. 46 (Considine Rebuttal) at Ex. MPC-R-11.
550
      ETI Ex. 46 (Considine Rebuttal) at 44-45, 47.
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expense that relates to the fully accrued accounts. According to ETI, Mr. Pous takes no notice of the
depreciation taken on new assets that are not included in rate base or recovered through depreciation
expense under existing rates. ETI witness Considine notes that Mr. Pous has essentially formulated
a one-sided exact recovery mechanism for depreciation expense that is completely unique in the
annals of base rates.551


           According to ETI, Mr. Pous also ignores that the remaining life depreciation method already
addresses any over- or under-accrual of depreciation expense. As depreciation rates and the
remaining life are adjusted over time, any over (under) recovery will be carried forward and the net
(if any) of the original investment less any accumulated reserve will begin to be recovered under the
new and future rate structures. This is the basic concept of remaining life depreciation rates. Thus,
ETI contends that no further actions or adjustments are appropriate.552


           The ALJs find that Mr. Pous’ recommendation has previously been rejected, by other
regulatory bodies. There is nothing in the arguments advanced by Cities that changes that fact.
Accordingly, the ALJs recommend the Commission reject Cities’ proposal.


           7. Other Depreciation Issues – Accumulated Provision for Depreciation

           ETI proposes to amortize the $21 million general plant deficiency over ten years. Both the
Cities and Staff agree with and use the accumulated depreciation reserve amounts per account from
Mr. Watson’s study.553 TIEC witness Pollock, in arguing against amortization of the amortized
general plant reserve deficiency, testified that this reserve deficiency should instead be simply
reallocated to other depreciable general plant accounts that have depreciation surplus.554


           Mr. Pollock discussed transferring the depreciation reserve between the amortizable and
depreciable general plant accounts. He failed to show, however, how the reserve reallocation would

551
      Id. at 43, 45.
552
      ETI Ex. 71 (Watson Rebuttal) at 78.
553
      Id. at 77.
554
      TIEC Ex. 1 (Pollock Direct) at 38-39.
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be computed and provided no workpapers to substantiate his analysis. ETI argues that without a
verifiable basis for the computations, his recommendations to recompute general plant depreciation
accruals should be rejected.


          ETI also argues that Mr. Pollock’s testimony shows that he has reallocated the amortizable
general plant deficiency from the amortized general plant accounts to the depreciable general plant
accounts.       The depreciable plant accounts have shorter remaining lives than the ten-year
amortization of the deficiency proposed by ETI.555 ETI contends that common sense dictates that
transferring dollars from an account with a relatively longer remaining life to one with a shorter life
will yield a higher annual depreciation or amortization expense, yet Mr. Pollock somehow takes this
step and still arrives at a lower level of expense.


          According to ETI, Mr. Pollock’s methodology has the effect of “amortizing the difference
between the book and theoretical reserve over a time period that is significantly shorter than the
average remaining life of the assets within this function.”556 ETI asserts that such an adjustment to
depreciation and amortization expense was rejected by the Commission in the CenterPoint rate case,
and it should be rejected here.557


          TIEC argues that it does not propose any amortization of any accounts. Rather, TIEC states
that it is proposing a more efficient method for ETI to cure its deficits. Because ETI retired
equipment prior to the end of the assumed life of those assets, there is approximately a $21,300,000
deficiency in general plant accounts. ETI seeks to amortize the deficiency over ten years so that the
book reserve will “catch-up” with the theoretical depreciation reserve for the deficient reserve. TIEC
contends that its position is that the catch-up adjustment is not necessary.558




555
      ETI Ex. 13 (Watson Rebuttal) at Ex. DAW-1, App. A-1 at 4.
556
      ETI Ex. 71 (Watson Rebuttal) at 75.
557
      Id. at 75-76.
558
      TIEC Ex. 1 (Pollock Direct) at 37.
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          The ALJs have reviewed the evidence and arguments advanced by the parties and find that
those of ETI are more persuasive. Accordingly, the ALJs recommend the Commission reject TIEC’s
recommendation.


D.        Labor Costs

          1. Payroll and Related Adjustments

          A number of parties suggest various adjustments to ETI’s proposed payroll and related costs.
In the application, ETI’s Test Year payroll costs were adjusted downward by $957,695 to reflect a
decrease in the employee headcount levels at ETI during the Test Year. At the same time, payroll
costs were increased in the amount of $1,105,871 to account for employee pay raises. The net result
was that ETI’s Test Year payroll expense was adjusted upward by $148,176. Similar calculations
were made for ESI employees, resulting in a net upward adjustment for ESI payroll expenses of
$852,493. Thus, ETI requested an upward adjustment of $1,000,669 ($148,176 plus $852,493) for
ETI and ESI payroll expenses.559


          Cities oppose one part of these proposed adjustments. As noted above, ETI is proposing an
upward adjustment to account for pay raises given to ETI and ESI employees. One set of those
raises was given to employees in early August 2011, one month after the end of the Test Year.
Another set of raises was given to employees in April 2012, roughly nine months after the end of the
Test Year. Cities witness Garrett testified that it is acceptable to make an adjustment for the raises
made in August 2011 because they occurred shortly after the end of the Test Year. However, he
stated that it is unreasonable to include an adjustment for the raises given in April 2012. He believes
that any increase in costs due to the April 2012 pay raises might be offset by changes in productivity
and the overall workforce that may occur during the same time period, such as the replacement of
higher-paid workers who retire with new, lower paid employees.560 Thus, Cities propose an
adjustment that would reverse ETI’s proposed increase for the April 2012 pay raises thereby



559
      ETI Ex. 8 (Considine Direct) at 24-25; 3 at Sched. A-3 and WP/P AJ22.
560
      Cities Ex. 2 (Garrett Direct) at 13-15.
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reducing payroll expense by $1,185,811.561 No other party makes a similar challenge to the April
2012 pay raise.


            With regard to the adjustments proposed by ETI, Staff witness Givens accepted the
adjustments for headcount changes and the pay raises, but recommended a further downward
adjustment of $778,034 to account for a further decrease in ETI employee headcount levels from 678
at Test Year-end to 660 as of February 2012. She also recommended an upward adjustment of
$158,589 to account for an increase in ESI employee headcount levels from 3,055 to 3,089 as of
December 2011.562 Ms. Givens also recommended that, in addition to adjusting payroll expense
levels, the more recent headcount numbers should be used to adjust the level of payroll tax expenses,
benefits expenses, and savings plan expenses.563 As an alternative to its primary line of attack
(discussed above), Cities agree with the adjustments recommended by Staff.


            ETI also agrees, in concept, with the adjustments recommended by Staff, but contends that
Ms. Givens made some errors in her calculations. First, according to ETI, Ms. Givens used
erroneous headcounts for the end of the Test Year for ETI and ESI. According to the Company,
ETI’s headcount at Test Year-end was 675 and ESI’s was 3,054. Ms. Givens wrongly used
headcounts of 678 and 3,055, respectively, which caused a double counting of three ETI employees
and one ESI employee.564 Second, Ms. Givens made an error in the calculation of benefits costs
associated with the updated ESI headcount. Ms. Givens inadvertently used the ETI percentage in the
calculation rather than the ESI percentage shown on her exhibit.565 Third, Ms. Givens’ adjustment
for savings plan expense was not necessary and is thus inappropriate. According to ETI witness
Considine, savings plan expense is already included in benefits expense levels so it would be double
counting to adjust for both benefits expense and savings plan expense.566 Fourth, Ms. Givens’


561
      Id. at 19.
562
      Staff Ex. 1 (Givens Direct) at 10-12.
563
      Id. at 13-15.
564
      ETI Ex. 46 (Considine Rebuttal) at 32-33.
565
      Id. at 33.
566
      Id.
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full-time equivalent calculations need to be corrected. She included an incorrect assumption
regarding part time employee salaries. Ms. Givens assumed that a part time employee’s average
salary is 50 percent of the full time average salary. In his rebuttal testimony, Mr. Considine
provided the correct calculation of full time equivalents, thereby making it unnecessary to rely upon
an assumed average.567 According to Mr. Considine, the combined impacts of these errors is that
Ms. Givens’ ETI headcount adjustment overstated her O&M payroll reduction by $224,217, and her
ESI headcount adjustment understated her O&M payroll increase by $37,531.568 No party
challenged these corrected numbers.


           The ALJs are unpersuaded by Cities’ attempt to exclude the April 2012 pay raises. There
can be no real dispute about the fact that the pay raises are known and measurable. Moreover, there
is an obvious logical inconsistency in the Cities’ position – on the one hand they oppose
consideration of certain pay raises because they fall outside the Test Year, and on the other hand
they support consideration of headcount reductions even though they also fall well outside the Test
Year.


           The ALJs are also persuaded that, conceptually, the adjustments suggested by Staff are
reasonable and appropriate. Indeed, all parties agree on this point. Moreover, no party challenged
the corrections to Staff’s adjustments that were suggested by ETI, and the ALJs can find no basis for
challenging those corrections. Thus, the ALJs recommend that the Commission: (1) accept the
payroll adjustments proposed in the ETI application; and (2) accept the further payroll adjustments
proposed by Staff, corrected by ETI.


           2. Incentive Compensation

           One of the hotly contested issues concerns the extent to which ETI should be allowed to
recover, through its rates, the incentive compensation it pays to its employees. All parties agree that
Commission precedent generally identifies two types of incentive compensation, only one of which
is recoverable. Specifically, pursuant to Commission precedent, incentive compensation that is tied

567
      Id. at 34.
568
      Id. at MPC-R-5, and MPC-R-6.
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to operational goals is recoverable, while incentive compensation that is tied to financial goals is
not.569 In its application, however, ETI requests that it be allowed to recover its Test Year costs of
all of its incentive compensation costs, regardless of whether those costs are tied to operational goals
or to financial goals.


                        (a) Financially Based Incentive Compensation Should Not Be Recoverable

          ETI acknowledges that costs of incentive compensation tied to financial goals have typically
been disallowed by the Commission. However, ETI asks for the Commission to reconsider its
precedents on this issue.570 ETI argues that the Commission precedent is not, and should not be, a
hard and fast rule. ETI contends that the reason why cost recovery has been denied for incentive
compensation in prior rates cases is that, in those prior cases, there was “a lack of evidence showing
sufficient customer benefits.”571 ETI asserts that, in this case, it has assembled evidence not
previously considered by the Commission that shows the benefits to customers of using financial
measures in incentive compensation programs.                 For example, ETI argues that incentive
compensation that encourages the financial health of a company also benefits customers because:


          (1)        if a company maintains a financially healthy position, it will tend to have a
                     lower cost of capital that will in turn benefit customers through lower rates;
          (2)        a financially healthy company will be more prepared for emergency events
                     such as storms (which is particularly important in the Gulf Coast areas served
                     by ETI, which are subject to experiencing hurricanes); and
          (3)        with financial health, the costs of doing business with suppliers (of both
                     goods and services, including labor) will remain lower because, for example,
                     if a company was not in a financially stable condition, suppliers would tend
                     to demand higher prices or more onerous credit terms, resulting in higher
                     costs that would lead to higher rates than would otherwise occur.



569
    See, e.g.,TIEC Initial Brief at 51-52; see also AEP Application of AEP Texas Central Company for
Authority to Change Rates, See Docket No. 33309, Order on Rehearing at FoF 82 (Mar. 4, 2007); Application
of AEP Texas Central Company for Authority to Change Rates, Docket No. 28840, Order at FoF 164-170
(Aug. 15, 2005).
570
      Tr. at 1726.
571
      ETI Initial Brief at 129.
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           ETI witness Kevin Gardner, Vice President of Human Resources for ESI, testified that
customers receive benefits from those portions of the incentive compensation plans that are tied to
financial goals and measures. He explained that incentive compensation based on financial metrics
is a reasonable, necessary, and common component of compensation for companies like ETI. He
also opined that such incentives are a market necessity that ETI must include in its compensation
package so that it can hire and retain talented employees. He contended that customers benefit from
the incentives because they attract and keep qualified people.572 Mr. Gardner further testified that
disallowing financially-based incentives would only encourage utilities to eliminate them, thus
weakening the alignment of employees’ financial interests with the interest of the ratepayers in
having an efficiently run and financially healthy utility. He opined that having only operational
incentives could encourage utilities to overspend in some areas resulting in an incomplete,
unbalanced incentive program that would be atypical when compared with American industry in
general.573


           A second ETI witness, Dr. Jay Hartzell, also testified in favor of the concept of allowing ETI
to recover its costs associated with its financially-based incentive compensation. He is a professor
of finance in the business school at the University of Texas at Austin. Dr. Hartzell acknowledged
the historical distinction that has been made by the Commission between compensation tied to
financial measures and compensation tied to operational measures. However, he argues that this
distinction is based upon a “false dichotomy” and that the more appropriate focus should be on
whether customers benefit from the incentive in question, regardless of whether it is a financial or
operational incentive.574 Dr. Hartzell summarized his key opinion as follows:


           In my opinion, a well-designed compensation plan that includes incentive
           compensation tied to cost controls, profitability, and stock prices would tend to
           provide greater benefits to customers than an otherwise similar compensation plan
           that did not include any such incentive compensation.575


572
      ETI Ex. 36 (Gardner Direct) at 31.
573
      Id. at 32.
574
      ETI Ex. 15 (Hartzell Direct) at 3-4, 6, and 9-10.
575
      Id. at 7.
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          Dr. Hartzell argues that compensation linked to stock prices (provided it is part of a
reasonable, well-designed compensation plan) has four advantages for customers, :


x     helps ensure that managers will consider the financial health of the company when they make
      decisions, and it is in customers’ interests for the company be financially healthy;
x     provides an incentive for managers and employees to ensure that the company operates
      efficiently, resulting in lower rates than would otherwise occur;
x     provides a monitoring mechanism for managerial decision-making and the overall quality of
      management; and
x     results in lower customer costs because capital markets will tend to reward efficient long-term
      investments or capital expenditures.576

Dr. Hartzell cited a number of studies which support the theory that the benefits of incentive
compensation linked to stock price and profitability measures extend to customers of the company,
such as by lowering the company’s cost of capital, increasing the company’s ability to respond to
external shocks, improving customer satisfaction, and increasing oversight on managerial
decisions.577


          Conversely, Dr. Hartzell opined that if the use of incentive compensation linked to
profitability and stock prices is discouraged, via Commission policy disallowing recovery of the
costs of such compensation, then utility customers would be adversely affected. For example, if
employees did not receive any incentive compensation, salaries would have to be higher to attract
and retain the same quality of talent. Dr. Hartzell also testified that a compensation plan solely
consisting of salary and incentives based on operational performance could likely lead to “horizon
problems,” meaning that, absent incentives to focus on the long run health of the company, managers
might maximize their immediate compensation at the expense of longer-run benefits that the
customer could have enjoyed.578




576
      Id. at 13-14.
577
      ETI Ex. 15 (Hartzell Direct) at 15-21.
578
      Id. at 22-25.
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        All of the other parties oppose ETI’s efforts to recover the costs of its incentive
compensation tied to financial goals. The parties uniformly agree that the Commission has a well-
established and straightforward policy regarding the recoverability of incentive compensation
through rates: incentive compensation that is tied to operational goals is recoverable; incentive
compensation tied to financial goals is not.579 They contend that ETI’s position in this case flies
directly in the face of that policy. TIEC points out that ETI has offered no legal authority, such as a
statute or rule, which would justify its desire to have the Commission reverse its policy and allow
the recovery of incentive compensation tied to financial goals. State Agencies similarly argue that
ETI failed to establish a reason why the Commission should deviate from its long-standing policy.
The parties also support the reasoning behind the Commission’s policy: that financially-based
incentives are of more immediate benefit to shareholders, not ratepayers, and therefore are not
necessary and reasonable for the provision of service.


        State Agencies point out that, in support of his theory that financially-based incentives
provide benefits to ratepayers, Dr. Hartzell relied upon studies of utilities in competitive markets.
Thus, State Agencies contend, the studies are of little to no benefit in evaluating the effects of
financially-based incentives upon ETI customers because ETI is a monopoly that is not subject to
competitive pressures. Moreover, State Agencies examine at length the underlying studies relied
upon by Dr. Hartzell and assert, essentially, that the studies do not fully support the findings that
Dr. Hartzell ascribes to them.


        Staff refutes ETI’s contention that the only reason why cost recovery has historically been
denied for financially-based incentive compensation is that there has been a lack of evidence
showing customer benefits. For example, Staff points out that, in one of the prior dockets cited by
ETI, the Commission disallowed recovery for financially-based incentive costs after stating,
“Incentive compensation based on financial measures or goals is of more immediate benefit to



579
   TIEC Reply Brief at 35; State Agencies Initial Brief at 14; OPC Reply Brief at 12; Staff Initial Brief at 56;
Cities Initial Brief at 67; see also, Application of AEP Texas Central Company for Authority to Change
Rates, Docket No. 33309, Order on Rehearing at FoF 82 (Mar. 4, 2007); Application of AEP Texas Central
Company for Authority to Change Rates, Docket No. 28840, Order at FoF 164-170 (Aug. 15, 2005).
SOAH DOCKET NO. XXX-XX-XXXX                    PROPOSAL FOR DECISION                            PAGE 170
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shareholders.”580 This suggests that the question is not, as ETI contends, whether the incentives
provide any benefit to ratepayers. Rather, the question is whether the incentives are primarily
intended to provide benefits to shareholders.


          Mark Garrett, an attorney and certified public accountant who works as a consultant in the
area of public utility regulation, testified on behalf of the Cities in opposition to cost recovery for
financially-based incentive compensation. He stated there are a number of reasons why it makes
sense to exclude financially based incentive costs from rates: (1) there is no certainty from year to
year what the level of incentive payments will be (because incentive payments are conditioned upon
future events and triggers that might not occur), thereby making it difficult to set rates and recover a
level of expense; (2) many of the types of factors that increase earnings per share—such as an
unusually hot summer or customer growth—are outside the control of employees and have no value
to customers; and (3) earnings-based incentives can discourage energy conservation.581 Mr. Garrett
also discussed the results of a survey of 24 other states, which revealed that 17 states closely follow
Texas’ approach, and none allow full recovery of incentive compensation.582


          Mr. Garrett testified that ETI will not be placed at a competitive disadvantage in its ability to
obtain and retain qualified employees if its financially-based incentives are disallowed. He stated
that the Company’s total payroll costs for 2011 were 10 percent above the market price, and that
most of the above-market payroll costs derived from the incentive program.583


          The ALJs conclude that ETI should not be entitled to recover its financially based incentive
compensation costs. Based upon prior Commission precedents, the ALJs conclude that the issue is
not, as ETI contends, whether such incentives might provide any benefits to customers. The proper
question to be asked is whether they provide benefits most immediately or predominantly to
shareholders. Without a doubt, the primary purpose of financially based incentives, such as

580
   Staff Reply Brief at 44, quoting Application of Oncor Electric Delivery Company for Authority to Change
Rates, Docket No. 35717, Order on Rehearing at FoF 92 (Nov. 30, 2009).
581
      Cities Ex. 2 (Garrett Direct) at 29-30
582
      Id. at 32-38.
583
      Id. at 45-46.
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incentives tied to earnings per share or stock price, is to benefit shareholders, not ratepayers. Even
construing Dr. Harzell’s testimony in the most generous light, any benefits that might accrue to
ratepayers would be merely tangential to that primary purpose.


          Moreover, even if the ALJs were to completely accept as true the opinions offered by
Dr. Hartzell, it would be of limited benefit to ETI because his opinions were almost completely
theoretical. The premise of his testimony was that “a well-designed compensation plan” that
includes incentive compensation tied to financial goals would “tend to provide greater benefits to
customers” than a plan that did not include such compensation.584 He stressed that the customer
benefits of incentive compensation tied to financial goals can only exist if such compensation is part
of a larger, reasonable, and well-designed overall compensation plan.585 However, he did not
meaningfully apply this abstract theory to ETI’s compensation plan. For example, Dr. Harzell did
not offer an evaluation of ETI’s compensation plan and conclude that it is “well designed,” nor did
he testify that ETI’s incentives tied to financial goals actually provide benefits to its customers. He
admitted that he did not study the details of ETI’s incentive plans, nor did he do any type of analysis
to see if the costs of ETI’s incentive programs outweighed their benefits.586 He did not know the
amounts of incentive compensation that was paid by ETI.587 One of his major premises was that
financially-based incentives can benefit customers by lowering their costs, but he did not know how
ETI customer’s costs compared with customer costs in the other Entergy operating companies.588
Another of his major premises was that financially-based incentives can benefit customers by
ensuring the financial health of the Company, but he made no attempt to determine whether ETI
was, in fact, a financially healthy company.589 By confining his testimony to the abstract, it is
impossible to know whether Dr. Hartzell believes that ETI’s incentive compensation tied to financial
goals achieves the customer benefits that he believes such compensation can theoretically achieve.


584
      ETI Ex. 15 (Hartzell Direct) at 7 (emphasis added).
585
      See, e.g., ETI Ex. 15 (Hartzell Direct) at 13.
586
      Tr. at 484.
587
      Tr. at 478.
588
      Tr. at 480.
589
      Tr. at 481-82.
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It is true that Mr. Gardner described some of the specifics of ETI’s incentive plans. However,
because Dr. Hartzell did not explain the metrics of what he would consider “a well-designed
compensation plan,” it is impossible to know if ETI’s plan meets those metrics.


           Simply put, the ALJs conclude that ETI has failed to establish a sufficient justification for
overturning the well-established Commission policy that financially based incentive compensation is
not recoverable.


                        (b) The Adjustment for Financially-Based Incentive Compensation Costs

           Having concluded that ETI is not entitled to recover the costs of its financially based
incentive programs, it is necessary to determine the amount of those costs so that they may be
removed from consideration in this rate case. The parties disagree on the correct amount. Staff
argues that $5.3 million of ETI’s incentive compensation is financially based.590 TIEC contends the
correct number is $6.2 million.591 Cities contend it is $8.4 million.592


           Broadly speaking, ETI has two categories of incentive compensation programs – annual
programs and long-term programs. ETI witness Gardner testified that 100 percent of ETI’s
long-term programs are financially based, whereas an average, representing a far lower percentage,
of the Company’s annual programs are financially based.593 Staff witness Givens applied those
percentages to determine her estimate of the amount spent by ETI in the Test Year on financially
based incentives. As to the Company’s long-term programs, she recommended removing the entire
costs of those programs (i.e. 100 percent) from the cost of service. As to the Company’s annual
programs, she recommended removing average percentage of the costs of those programs.
Ms. Givens then applied the FICA tax rate to the total amount she identified as financially based
costs to account for direct taxes that ETI would have paid as a result of those costs. By her estimate,

590
   Staff Initial Brief at 56. (As discussed more below, Staff’s original estimate was roughly $5.6 million.
The estimate was reduced, however, in response to supplemental payroll tax information supplied to Staff by
ETI.)
591
      TIEC Initial Brief at 53-54.
592
      Cities Initial Brief at 70.
593
      ETI Ex. 36 (Gardner Direct) at 30.
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the FICA taxes associated with ETI’s financially based incentives paid in the Test Year totaled
$429,096. In total, Ms. Givens recommended removing $5,609,093 (representing ETI’s financially
based incentives paid in the Test Year, plus FICA taxes associated with those payments) from ETI’s
requested O&M expenses. However, based upon subsequent additional information supplied by
ETI594 relative to the actual payroll taxes paid by the Company for its financially based incentive
compensation, Staff has agreed to lower its estimate of FICA taxes from $429,096 to $143,801.
Thus, Staff now recommends removing $5,323,798 (representing ETI’s financially based incentives
paid in the Test Year, plus FICA taxes associated with those payments) from ETI’s requested O&M
expenses.595


          Like Ms. Givens for Staff, TIEC witness Pollock relied on the numbers and percentages
concerning ETI’s incentive programs that were provided by Mr. Gardner. However, Mr. Pollock
calculated those numbers and percentages in a slightly different manner, leading to a different
recommended reduction amount. Just as Ms. Givens did, as to the Company’s long-term programs,
he recommended removing the entire costs of those programs from the cost of service. ETI witness
Gardner testified that actual percentages of each annual program were quite different than the
average percentages for all programs used by Ms. Givens.596 Thus, as to the Company’s annual
programs, while Ms. Givens applied the average percentage reduction to all of the annual programs,
Mr. Pollock applied the actual percentage reductions applicable to each of the annual programs.
Based on Mr. Pollock’s calculations, TIEC recommends removing $6,196,037 (representing ETI’s
financially based incentives paid in the Test Year) from ETI’s requested O&M expenses.597 TIEC
appears not to have taken into account any payroll taxes associated with ETI’s financially based
incentives.


          Cities witness Garrett took a substantially different approach when he calculated his estimate
of ETI’s financially based incentive costs. He agreed with Ms. Givens and Mr. Pollock that

594
      ETI Ex. 46 (Considine Rebuttal).
595
      Staff Ex. 1 (Givens Direct) at 15-22; Staff Initial Brief at 56-63.
596
      ETI Ex. 36 (Gardner Direct) at 30 and KGG-4.
597
      TIEC Ex. 1 (Pollock Direct) at 41-45 and JP-7; TIEC Initial Brief at 51-54.
SOAH DOCKET NO. XXX-XX-XXXX                   PROPOSAL FOR DECISION                         PAGE 174
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100 percent of the Company’s long-term program costs should be removed from the cost of service.
As to the annual programs, however, Mr. Garrett defined what qualifies as “financially based” much
more broadly than ETI, Staff, and TIEC. ETI witness Gardner testified that, when the Company’s
five annual programs were averaged together, specific percentages of those programs were
financially based, aimed at “cost control,” and aimed at “cost control, operational, safety.” 598
Mr. Garrett added together the percentages representing the financially-based costs, the cost-control
costs, and roughly one-third of the cost-control, operational safety costs to arrive at the figure he
identified as the amount of ETI’s costs for its annual programs that is “related to financial
performance measures.”599 Cities contend this approach is supported by the decision in a prior
docket.600       Based on Mr. Garrett’s calculations, Cities recommend removing $8,397,232
(representing ETI’s incentives “related to financial performance measures” paid in the Test Year)
from ETI’s requested O&M expenses.601 Mr. Garrett also agreed with Ms. Givens that an additional
reduction should be made to account for the FICA taxes that ETI would have paid as a result of
those costs.602


          The ALJs reject Cities’ attempt to broadly expand the definition of what qualifies as a
financially based incentive to include items such as cost control measures. Cities’ primary
justification for doing so is that the Commission has done so previously in the AEP Texas case. As
pointed out by ETI, however, the Commission did so in that case merely because AEP Texas lumped
its cost control measures in with its financially based incentive costs. The evidence in this case
demonstrates that ratepayers benefit when a utility incentivizes its employee to control costs. Even
TIEC witness Pollock testified that “incentives that encourage employees to minimize costs are
probably more or less in the best interest of ratepayers.”603 ETI further provided evidence


598
      ETI Ex. 36 (Gardner Direct) at 30 and KGG-4.
599
      Cities Ex. 2 (Garrett Direct) at 39-40, 46-50, MG2.10.
600
   Cities Initial Brief at 68, Application of AEP Texas Central Company for Authority to Change Rages,
Docket No. 28840, Final Order (August 15, 2005).
601
      Cities Ex. 1 (Garrett Direct) at 51-52 and MG2.10; Cities Initial Brief at 70.
602
      Cities Ex. 1 (Garrett Direct) at 53.
603
      Tr. at 1528.
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establishing that cost control incentives that result in lower costs for the Company likewise result in
lower rates for customers.604


            As to the approaches advocated by TIEC and Staff, the ALJs conclude that TIEC’s approach
more accurately captures the true cost of ETI’s financially based incentive programs. Rather than
averaging across all of ETI’s annual programs (as was done by Staff), TIEC used the percentage
applicable to the single annual program that included a component of financially based costs. Thus,
the ALJs recommend removing $6,196,037 (representing ETI’s financially based incentives paid in
the Test Year) from ETI’s requested O&M expenses. Additionally, the ALJs agree with Staff and
Cities that an additional reduction should be made to account for the FICA taxes that ETI would
have paid as a result of those costs. That amount is not specifically known at this time.


            3. Compensation and Benefits Levels

            In the application, ETI included, as part of its labor costs, $54,965,005 in base payroll paid
by ETI and ESI in the Test Year. It also included $20,428,817 in costs associated with various
benefits (such as medical/dental, and life insurance) that ETI and ESI provided to their employees.605
Cities contend that the amounts for base pay and the benefits package should be reduced by
$989,370 and $2,860,034, respectively, because the amounts paid were above the market price.606
No other party challenges the reasonableness of the base payroll and benefits package.


            As to base payroll, Cities contends that the amount paid by ETI and ESI was 1.8 percent
above the prevailing market price (above market).607 Cities witness Garrett acknowledges that ETI
and ESI are free to pay their employees at above market wages, but he contends that ratepayers
should only be asked to pay the market rate for wages, which he contends constitute the only
“necessary” costs of providing utility service. Thus, Mr. Garrett and Cities recommend a 1.8 percent



604
      ETI Ex. 50 (Gardner Rebuttal) at 6-7, ETI Initial Brief at 137-38.
605
      Cities Ex. 2 (Garrett Direct) at 25, MG2.8, and MG2.9.
606
      Id.
607
      Id. at 25 and MG2.8.
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downward adjustment to base payroll expense (or $989,370) “to bring the company’s base payroll
down to a market-based level.”608


           As to the Company’s benefits package, Cities points out that the amount paid by ETI and ESI
was 14 percent above market when compared to a peer group of Fortune 500 companies.609 Cities
witness Garrett again contends that ratepayers should only be asked to pay the market rate for
benefits, which he contends constitute the only “necessary” costs of providing utility service. Thus,
Mr. Garrett and Cities recommend a 14 percent downward adjustment to benefits expenses (or
$2,860,034).610


           ETI concedes that its Test Year base pay was 1.8 percent “above the market median,” but
argues that this is not the same thing as being “above market.” As ETI witness Gardner explained,
“being ‘at market’ means being within a reasonable range, such as +/-10 percent, of the market
median; therefore, the Company’s base pay levels are at market.”611 According to Mr. Gardner,
some compensation consultants use an even broader range, such as a +/- 15 percent range, for
determining whether compensation levels are at market.612 Mr. Gardner testified that, because no
two jobs are likely to be identical, attempting to benchmark jobs to a “market price” is an inexact
science, involving inherent imprecision. Thus, Mr. Gardner testified that, when using a benchmark
analysis to compare companies’ levels of compensation, it is advisable to view the market level of
compensation as a range (e.g., +/- 10 percent of a mid-point) rather than a precise, single point.613


           ETI also disputes Cities’ contention that the Test Year costs of the Company’s benefits
package were 14 percent “above market.” Mr. Gardner acknowledged that the costs were 14 percent
higher than those of Fortune 500 companies, but he pointed out the costs were only 1 percent above


608
      Id. at 26-27 and MG2.8.
609
      Id. at 58 and MG2.9; ETI Ex. 36 (Gardner Direct) at 41-42.
610
      Cities Ex. 2 (Garrett Direct) at 58-59 and MG2.9.
611
      ETI Ex. 50 (Gardner Rebuttal) at 11.
612
      ETI Ex. 36 (Gardner Direct) at 23, and ETI Ex. 50 (Gardner Rebuttal) at 11 n. 1.
613
      ETI Ex. 50 (Gardner Rebuttal) at 11-12.
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the market median of a peer group of utility companies.614 ETI contends that the comparison against
the peer group of utility companies provides a more appropriate comparison for ETI than Fortune
500 companies. ETI also points out that, even if equal weight were given to the comparisons against
the Fortune 500 companies and the peer utilities group, the value of the Company’s benefit plans
would average within a +/- 10 percent range and, therefore, be at market. Thus, ETI argues that its
benefit plan levels are within a reasonable range, and no disallowance should be required.615


           The ALJs conclude that ETI has met its burden to prove the reasonableness of its base pay
and incentive package costs. The ALJs agree that it is reasonable to view market price for these
categories of costs as lying within a range of +/- 10 percent of median, rather than being a single
point along a spectrum. As to both base pay and the incentive package, ETI has proven that its costs
fall within such an acceptable range. Accordingly, the ALJs recommend rejecting the adjustments
sought by Cities.


           4. Non-Qualified Executive Retirement Benefits

           ETI provides three types of supplemental executive retirement plans: the Pension
Equalization Plan, the Supplemental Retirement Plan, and the System Executive Retirement Plan.616
In the application, ETI included, as part of its labor costs, $2,114,931 in costs associated with its
executive retirement plans. The expenses represent non-qualifying retirement plan expenses
designed to provide retirement benefits to key managerial employees and executives who are invited
to participate in the plans. They are generally available only to employees and executives earning
more than $245,000 per year.617


           On behalf of the Staff, Ms. Givens recommended a complete disallowance of the costs for
these programs, on the grounds that they are offered to only select, highly compensated employees
and are excessive. Ms. Givens offered the opinion that the expenses were not reasonable and

614
      ETI Ex. 36 (Gardner Direct) at 42.
615
      ETI Ex. 50 (Gardner Rebuttal) at 13-14; ETI Initial Brief at 139-142.
616
      ETI Ex. 50 (Gardner Rebuttal) at 14.
617
      Staff Ex. 1 (Givens Direct) at 22-23; Cities Ex. 2 (Garrett Direct) at 54.
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necessary for the provision of electric utility service and were not in the public interest.618 On behalf
of Cities, Mr. Garrett agreed with Ms. Givens’ recommendation, arguing that it is fair to have
ratepayers pay for benefits included in regular pension plans, but that shareholders ought to pay for
any additional benefits included in supplemental plans, “since these costs are not necessary for the
provision of utility service, but are instead discretionary costs of the shareholders.”619 Mr. Garrett
also testified that costs associated with supplemental executive retirement plans are typically
excluded by utility commissions in Oklahoma, Oregon, Idaho, Arizona, and Nevada.620 On behalf of
OPC, Dr. Szerszen also recommended a complete disallowance of the portion of these costs
allocated from ESI to ETI.621 She stated that ETI has not shown that ratepayers benefit from the
expenses, the costs are not necessary to provide utility service, and that the ESI allocation method is
unjustified.622


          ETI disagrees with all of these criticisms and maintains that the costs of the plans should be
recoverable. ETI witness Gardner testified that the supplemental executive retirement plans are
needed for attracting, retaining, and motivating highly competent and qualified leaders. He
explained that the Pension Equalization Plan provides supplemental retirement benefits to account
for the fact that Internal Revenue Code regulations limit the level of retirement benefits that qualify
for tax treatment favorable to ETI and Entergy. The existence of this supplemental benefit program
allows the Company to pay retirement benefits to highly-compensated employees that are
proportionate to the compensation they receive while active in their employment. The Supplemental
Retirement Plan and the System Executive Retirement Plan provide supplemental benefits beyond
the amounts restricted in the qualified plan to some participants to attract, retain, and motivate
employees.623 According to Mr. Gardner, these types of retirement benefits are widely provided by


618
      Staff Ex. 1 (Givens Direct) at 23; Staff Initial Brief at 64.
619
      Cities Ex. 2 (Garrett Direct) at 55; Cities Initial Brief at 71-72.
620
      Cities Ex. 2 (Garrett Direct) at 56-57.
621
   OPC Ex. 1 (Szerzen Direct) at 68. Dr. Szerzen quantifies the costs of the plans as $1,391,861 (a much
lower estimate than those of Ms. Givens and Mr. Garrett).
622
      Id. at 68-69.
623
      ETI Ex. 50 (Gardner Rebuttal) at 15-16.
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companies within the utility business sector.624 Accordingly, ETI argues that it needs to offer them
in order to be competitive in the employment market with peer companies, and thereby to retain and
adequately compensate these employees in terms of future retirement benefits.


           The ALJs conclude that the supplemental executive retirement plans are not reasonable and
necessary for the provision of electric utility service and are not in the public interest. They are
non-qualifying retirement plan available only to employees and executives earning more than
$245,000 per year, and they constitute benefits over and above the Company’s standard retirement
benefits package. Because these costs are not necessary for the provision of utility service, but are
instead discretionary costs, they should be paid by the shareholders. Accordingly, the ALJs
recommend an adjustment to remove $2,114,931, representing the full costs associated with ETI’s
non-qualified executive retirement benefits.


           5. Employee Relocation Costs

           In the application, ETI included, as part of its labor costs, $436,723 in employee relocation
costs.625 ETI contends that, in order to be competitive in the employment market, it must provide
relocation assistance to certain of its employees. ETI witness Gardner testified that ETI’s relocation
policies and costs are reasonable and consistent with general industry practice. He also testified that
the Company’s average relocation costs are in line with the relocation costs for the companies
surveyed by the Employee Relocation Council.626


           Staff recommends an adjustment to remove the entire $436,723 of ETI’s relocation
expenses.627 No other party challenged the legitimacy of relocation expenses. Staff points out that
ETI pays 110 percent of the market median for total annual compensation.628 Staff contends that the
fact that ETI pays more than the average market wage demonstrates that employees should be

624
      Id. at 16.
625
      Staff Ex. 1 (Givens Direct) at 25.
626
      ETI Ex. 36 (Gardner Direct) at 45-46.
627
      Staff Initial Brief at 64; Staff Ex. 1 (Givens Direct) at 24.
628
      Staff Ex. 1 (Givens Direct) at 24 (citing ETI Ex. 36 (Gardner Direct) at 26).
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sufficiently enticed to join and move around within its organization without the need for ETI to pay
relocation expenses to attract employees. Therefore, Staff argues that the relocation expenses do not
meet the reasonable and necessary standard required for inclusion in cost of service, nor are the
expenses in the public interest.629 Staff also points out that similar types of payments were removed
from cost of service in recent proceedings, such as in Docket No. 28906, where payments for
moving expenses or signing bonuses were removed from cost of service.630


           ETI responds by pointing out that Staff does not challenge the reasonableness of the amount
spent on relocations by ETI. It also contends that most of its peers offer moving assistance. Thus, it
would be competitively disadvantaged if it did not offer it as well. ETI reiterates that its relocation
costs are reasonable and necessary and should be authorized.631


           The ALJs conclude that ETI has the better argument. There is no allegation that ETI was too
lavish in its relocation expenditures. The only complaint offered by Staff is that ETI’s overall
compensation costs are 110 percent of the market median. It does not necessarily follow that the
relocation program is unnecessary. ETI provided substantial evidence that, without a relocation
program, it would be at a competitive disadvantage with its peers. Accordingly, the ALJs reject
Staff’s request to disallow the Company’s relocation expenses.


           6. Executive Perquisites

           In the application, ETI included, as part of its labor costs, $40,620 in costs associated with its
executive perquisites. Those perquisites consist of financial counseling and tax gross-ups for system
officers and executives. Specifically, the financial counseling program promotes maximizing
investment growth opportunities for eligible officers and executives, and allows reimbursement for
certain expenses incurred for personal financial counseling services.632 Staff recommends an


629
      Staff Initial Brief at 64; Staff Ex. 1 (Givens Direct) at 24.
630
   Staff Initial Brief at 64; Staff Ex. 1 (Givens Direct) at 24, citing Application of LCRA Transmission
Services Corporation to Change Rates, Docket No. 28906, Final Order (Apr. 5, 2005).
631
      ETI Initial Brief at 143.
632
      Staff Ex. 1 (Givens Direct) at 23.
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adjustment to remove the full cost of the executive perquisites ($40,620), reasoning that the costs are
not reasonable and necessary for the provision of electric utility service.633 ETI does not oppose that
adjustment.634 The ALJs agree that the adjustment is warranted. Therefore, the ALJs recommend an
adjustment to remove $40,620, representing the full cost of ETI’s executive perquisite costs.


E.         Interest on Customer Deposits

           Staff witness Givens adjusted ETI’s requested interest expense of $68,985 by removing
$(25,938) from FERC account 431.635 This decrease is a result of applying the interest rate of
0.12 percent for calendar year 2012 on deposits held by utilities.636 Using the active customer
deposits amount of $35,872,476 and the 2012 interest rate, Ms. Givens calculated a recommended
interest expense of $43,047 ($35,872,476 multiplied by .12 percent).637


           This change, which reflects Commission-approved interest rates for 2012 as set in December
2011, complies with Project No. 39008 and ETI agreed with this amount. Accordingly, the ALJs
recommend that the Commission approve this amount.


F.         Property (Ad Valorem) Tax Expense

           During the Test Year, ETI’s property tax expense equaled $23,708,829.638 Patricia
Galbraith, ETI’s Tax Officer, testified that a pro forma adjustment should be made to this level of
expense for a known and measurable change that reflects the level of property tax expense ETI will
experience in the Rate Year. Specifically, her proposed adjustment would increase the Test Year
level of expense by $2,592,420 to $26,301,249.639 As Ms. Galbraith testified, ETI’s property tax
expense for the calendar year 2012 will be paid in January of 2013 and be based on 2011 calendar

633
      Staff Initial Brief at 65; Staff Ex. 1 (Givens Direct) at 23.
634
      ETI Initial Brief at 144.
635
      Staff Ex. 1 (Givens Direct) at 24.
636
      Setting Interest Rates for Calendar Year 2012, Project No. 39008, Order (Dec. 8, 2011).
637
      Staff Ex. 1 (Givens Direct) at 24-25.
638
      ETI Ex. 26 (Galbraith Direct) at 5; ETI Ex. 3 at Sched. G-9.
639
      ETI Ex. 26 (Galbraith Direct) at 5 and PAG-1; ETI Ex. 3 at Sched. G-9.
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year-end values for both net operating income and net plant amounts.640 Her proposed adjustment is
based on an expected ad valorem rate increase of 1 percent and expected increases in both net plant
values and ETI net operating income that will equal 9.81 percent.641


          TIEC, Cities, and Staff oppose the property tax adjustment proposed by ETI. TIEC argues
that ETI’s proposed adjustment should be rejected entirely, on the grounds that it is not a known and
measurable change from ETI’s Test Year property tax costs. Ms. Galbraith admitted that she does
not know, with certainty, what the relevant property tax rate will be in 2012, nor has ETI received
any tax bills advising that tax rates will rise.642 Thus, TIEC witness Pollock testified that ETI’s
proposed adjustment is not known and measurable and recommended that the Commission reject the
adjustment and include only the Test Year level of expense in cost of service.643 TIEC further points
out that the Commission has twice rejected requests to include projected property tax expense in
rates.644 For example, in Docket No. 28813, Cap Rock prepared an independent analysis indicating
that property taxes were expected to increase to $2,700,000 per year from its test year tax level of
approximately $900,000 per year. The analysis used an estimated tax assessment of $110,000 with
an estimated tax rate of $2.47 per $100 of value. The ALJs in that case concluded that the property
tax increases were estimates at the time of the hearing, and thus they were not known and
measurable and should not be allowed.645 Subsequently, the Commission adopted the ALJs’




640
      Tr. at 1235.
641
      ETI Ex. 26 (Galbraith Direct) at PAG-1.
642
      Tr. at 1221, 1238.
643
      TIEC Ex. 1 (Pollock Direct) at 40–41.
644
   In re Cap Rock Corp., Petition of PUC (Staff) to Inquire into the Reasonableness of the Rates and Services
of Cap Rock Energy Corporation, Docket No. 28813, Order on Rehearing at FoF 137 (Nov. 9, 2005) (“Cap
Rock failed to prove any increase in property taxes above those in the test year-$899,597-was known and
measurable.”); Application of Gulf States Utilities Company for Authority to Change Rates, Application of
Sam Rayburn G&T Electric Coop., Inc. for Sale Transfer or Merger, Appeal of Gulf States Utilities Company
from Rate Proceedings of Various Municipalities, Docket Nos. 8702, 8922, 8939, 8940, 8946, 8233, 8944,
8945, 8947, 8948 and 8949, Order at FoF 111 (May 2, 1991) (“The 1988 calendar year level of actual
property taxes paid should be used in determining rate year taxes because it is a known and measurable
change.”).
645
      Docket No. 28813, PFD at 99 (Mar. 17, 2005).
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finding.646 The Commission rejected a similar request from ETI’s predecessor Gulf States Utilities
(GSU).647 In consolidated Docket No. 8702, the Commission rejected GSU’s request for projected
1989 property taxes and instead only allowed the actual calendar year property tax expenses.648 In
both cases the Commission found that projected tax expense is not a known and measurable
change.649 Accordingly, TIEC contends that ETI’s request for a forecasted tax expense increase
should be rejected.650


          Staff concedes that some level of increase is warranted but argues that the increase should be
smaller than ETI is asking for. Rather than an increase of $2,592,420, Staff contends that ETI’s Test
Year property tax expenses should be adjusted upward by only $1,214,688.651 Staff witness Givens
arrived at this increase by applying the effective tax rate for the calendar year 2011 to the Staff’s
Test Year end plant in service recommendation. She testified that both of these inputs to her
calculation are known and measurable and thus may be used to determine the increase.652


          Cities also concede that some level of increase is warranted, but argue that the increase
should be smaller than ETI is asking for, and smaller than Staff proposes. Cities contend that ETI’s
Test Year property tax expenses should be adjusted upward by only 1,134,442.653 Cities witness
Garrett offered the opinion that ETI’s proposed adjustment was based on estimates that were
unreasonably high when compared to the actual tax valuation increases experienced since 2008. Mr.
Garrett arrived at his projected increase in tax expense by applying the average annual valuation
increase experienced over the period of 2009-11 to net plant value for 2011. Cities argue that both



646
      Docket No. 28813, Order on Rehearing at FoF 137 (Nov. 9, 2005).
647
      Docket No. 8702, Order at FoF 111 (May 2, 1991).
648
      Docket No. 8702, Order at 52.
649
   Docket No. 28813, Order on Rehearing at FoF 137 (Nov. 9, 2005); Docket No. 8702, Order at 52, FoF
111 (May 2, 1991).
650
      TIEC Initial Brief at 54-56.
651
      Staff Ex. 1 (Givens Direct) at 25.
652
      Id. at 25-26.
653
      Cities Ex. 2 (Garrett Direct) at 61.
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of these inputs to the calculation are known and measurable and thus may be used to determine the
increase.654


            ETI responds to its opponents by pointing out that the Commission has, in the past,
recognized that the adjustment proposed by Staff, which was obtained by applying a historical
effective tax rate to the level of test year end plant in service, is known, measurable, and
appropriate.655 ETI also notes that, although it had not done so at the time Ms. Galbraith filed her
testimony, ETI has since filed its 2011 year end FERC Form 1 data and now knows both the final net
income amounts and net plant values for year end 2011 that will be used to determine the
Company’s 2012 tax expense (that will be paid in January of 2013).656 ETI contends that those
known values are substantially larger than the estimates used by Ms. Galbraith when she calculated
the proposed adjustment, such that the known increases in 2011 net operating income and net plant
amounts over 2010 are so large that, even without the 1 percent increase in tax rate assumed in the
property tax adjustment, Rate Year property tax expenses will be larger than the $26,301,249
amount requested by the Company.657


            The issue with regard to property taxes is whether a level of increase is known and
measurable. The ALJs conclude that the approach taken by Staff does the best job of generating a
known and measurable value for ETI’s property tax burden in the Rate Year. As explained above,
Staff’s approach is supported by prior Commission precedent. Moreover, unlike the approaches
advocated by ETI and Cities, Staff’s approach requires no guesswork about future tax rates.
Accordingly, the ALJs recommend that ETI’s property tax burden should be adjusted upward by



654
      Id.
655
   ETI Initial Brief at 145; see also, Application of AEP Texas Central Company for Authority to Change
Rates, Docket No. 28840, Final Order at FOF 189-191 (Aug. 15, 2005); Petition of General Counsel to
Inquire Into the Reasonableness of the Rates and Services of Central Telephone Company of Texas, Docket
No. 9981, 19 Tex. P.U.C. BULL. 936, 1080-82, 1217 (Sept. 8, 1993); Application of Central Power and Light
Company for Rate Changes and Inquiry Into the Company’s Prudence with Respect to South Texas Project
Unit 2, Docket No. 9561, 17 Tex. P.U.C. BULL. 157, 231-232 (Dec. 19, 1990).
656
      Tr. at 1236-37.
657
      ETI Initial Brief at 146-47.
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applying the effective tax rate for the calendar year 2011 to the final, adopted Test Year-end plant in
service value for ETI.


G.         Advertising, Dues, and Contributions

           In the application, ETI included, as part of its operating expenses, $2,046,214 in costs
associated with advertising, dues, and contributions.658 Staff recommended an adjustment to remove
$12,800, representing contributions to organizations primarily focused on influencing legislative
activities. Staff reasons that these costs are not reasonable and necessary for the provision of electric
utility service.659 ETI makes no response to the suggested adjustment.660 The ALJs agree that the
adjustment is warranted. Therefore, the ALJs recommend an adjustment to remove $12,800 from
ETI’s costs of advertising, dues and contributions.


H.         Other Revenue-Related Adjustments

           Several items within the Company’s revenue requirement are interrelated. This means that
changes to one area or item will impact one or more additional items, such as the Texas state gross
receipts tax, the PUC Assessment tax, and Uncollectible Expenses.661 From the discussions in
briefs, it does not appear that there are any substantive differences among the parties regarding these
amounts, which will ultimately be determined during number running.


I.         Federal Income Tax

           As explained by ETI witness Rory Roberts, the Company calculated its income tax expense
in the cost of service by taking into account only the revenues and expenses included in the cost of
service.662 To the extent the Commission makes changes to the revenues and expenses that are
ultimately included in the cost of service, the income tax expense amount included in the cost of

658
      ETI Ex. 3, Sched. G-4.
659
      Staff Initial Brief at 66; Staff Ex. 1 (Givens Direct) at 26.
660
      ETI Initial Brief at 147.
661
      Staff Ex. 1 (Givens Direct) at 28-29.
662
      ETI Ex. 21 (Roberts Direct) at 10; Ex. 3 Sched. G-7.
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service will change accordingly. This represents a proper matching of income tax effects to the
expenses and revenues that produced those tax effects.663


          Mr. Roberts contended that the Commission’s past practice of reducing tax expense for a
consolidated tax adjustment based on some measure of the tax “savings” the utility realized by
joining in a consolidated group federal income tax return was inappropriate. He testified that it is
improper to reduce tax expense for deductions or losses that are not also included in the cost of
service. In the case of the Commission’s consolidated tax adjustment, tax expense is reduced to the
extent that utility income is used to offset non-utility affiliate losses, even though those losses are
not included in cost of service or borne in any manner by the utility’s customers.664


          Despite his disagreement with the approach, Mr. Roberts performed a calculation of the
adjustment using the interest credit methodology adopted by the Commission. He concluded that,
instead of positive taxable income, ETI had net tax losses over the 15-year calculation period and
thus provided no taxable income that could be used to offset affiliate losses.665 In fact, over the
15-year period, ETI’s tax losses were offset by taxable income produced by other affiliates. Thus,
ETI contends that, were the Commission to be consistent in applying its interest credit methodology,
it should increase ETI tax expense included in cost of service due to the fact that its affiliates’
taxable income had to be used to offset ETI’s tax losses. Nevertheless, in its application, ETI
rejected the interest credit methodology and has not requested that ETI’s tax expense be increased as
a result of the consolidated tax adjustment calculation. No other party to the proceeding challenged
the Company’s position on federal income tax expense in testimony or at the hearing. The ALJs find
no reason to do so either.


J.        River Bend Decommissioning Expense

          ETI has an ownership interest in River Bend. In the application, ETI requested that
$2,019,000 be included in its cost of service to account for the Company’s annual decommissioning

663
      ETI Ex. 21 (Roberts Direct) at 10.
664
      Id. at 10-11.
665
      Id. at 10, and RLR-5.
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expenses associated with River Bend.666 This is the same amount that was requested and approved
on December 13, 2010, in Docket No. 37744.667 The amount of $2,019,000 was derived from an
ETI decommissioning study that was completed in 2009. In this case, ETI chose not to propose any
change to its 2009 estimate. ETI contends that this decision is supported by an August 9, 2011,
letter from the Nuclear Regulatory Commission.668


          Cities argue that the decommissioning expense should be reduced to $1,126,000.669 Cities
point out that the larger amount sought by ETI was merely the amount agreed to by the parties, as
opposed to being substantively considered and approved by the Commission in Docket
No. 37744.670 In the current case, ETI was asked through discovery to provide an updated estimate
of the annual decommissioning expense responsibility for Texas retail customers calculated using
the most current Texas jurisdictional decommissioning fund balance. ETI responded that the current
annual decommissioning revenue requirement is $1,126,000.671


          Under P.U.C. SUBST. R. 25.231(b)(1)(F)(i), the annual cost of decommissioning for
ratemaking purposes must “be determined in each rate case based on . . . the most current
information reasonably available regarding the cost of decommissioning, the balance of funds in the
decommissioning trust, anticipated escalation rates, the anticipated return on the funds in the
decommissioning trust, and other relevant factors.” The cost determined must then be expressly
included in the cost of service established by the Commission’s order.


          The parties agree that $1,126,000 is the best estimate of the current annual revenue
requirement to meet ETI’s estimated decommissioning cost. However, ETI relies on P.U.C. SUBST.
R. 25.231(b)(1)(F)(iv) and Staff witness Cutter’s testimony to contend that it need not adjust the

666
      ETI Ex. 3 Scheds. M-1 and M-2; ETI Ex. 8 (Considine Direct) at 57-58.
667
      ETI Ex. 8 (Considine Direct) at 58.
668
      Id. at 58 and MPC-2.
669
      Cities Ex. 2 (Garrett Direct) at 64-65.
670
  Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Final Order at
FoF 32 (Dec. 13, 2010); Cities Initial Brief at 73.
671
      Tr. at 348-49.
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current amount being charged.672 Pursuant to subpart (iv), ETI is required to periodically study its
decommissioning costs, and such a study must be done “at least every five years.” Because its last
study was done in 2009, ETI contends that it need not do a new study now, but may simply rely of
the outcome of its last study, which showed that its annual revenue requirement is $2,019,000.673


            Cities agree that ETI is not required to conduct a new decommissioning study at this time.
However, the most current information reasonably available clearly shows that the annual amount
required to meet the total cost determined in the Company’s last decommissioning study has
decreased. Cities argue that to ignore the most current information available disposal would
unreasonably shift future costs to current customers and would be a violation of P.U.C. SUBST.
R. 25.231(b)(1)(F)(i). The ALJs agree. ETI’s annual decommissioning revenue requirement should
reflect the most current calculation of $1,126,000. Therefore, an adjustment of $893,000 to the pro
forma cost of service is needed to reflect the difference between the requested level for
decommissioning costs of $2,019,000 and recommended level of $1,126,000.


K.          Self-Insurance Storm Reserve Expense [Germane to Preliminary Order Issue No. 5]

            In prior dockets, the Commission authorized ETI to recover $3,650,000 annually for storm
damage expenses and to maintain a reasonable and necessary storm damage reserve account of
$15,572,000.674       ETI requests to increase the authorized storm damage reserve account to
$17,595,000 (an increase of $2,023,000) and to increase the annual accrual to $8,760,000 (an
increase of $5,110,000). ETI’s proposed annual accrual is composed of two elements: (1) an annual
accrual of $4,890,000 to provide for average annual expected losses from all storms that do not
exceed $100 million; and (2) a 20-year annual accrual of $3,870,000 to bring the reserve up from its
current deficit of $59,799,744 to ETI’s target reserve of $17,595,000.


            No party disputes that ETI’s proposal to self-insure for catastrophic property loss is
appropriate under PURA § 36.064 and P.U.C. SUBST. R. 25.231(b)(1)(G). However, Cities, OPC,

672
      ETI Ex. 46 (Considine Rebuttal) at 38-39.
673
      Id.
674
      Staff Ex. 4 (Roelse Direct) at 8.
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and Staff oppose the amount of ETI’s proposed annual accrual, and Cities and OPC also oppose
ETI’s proposed target reserve. The parties’ recommendations are:


                                          Annual Accrual       Target Reserve
                            Current        $3,650,000           $15,572,000
                            ETI            $8,760,000           $17,595,000
                            Cities         $6,150,339           $15,572,000
                            OPC-1          $2,335,047           $15,572,000
                            OPC-2          $3,650,000           $15,572,000
                            Staff          $8,270,000           $17,595,000

           The first component of ETI’s requested annual accrual is $4,890,000 for expected annual
losses. ETI explains that this is the amount of annual losses projected to be incurred by ETI from all
storm damage, except those over $100 million (the minimum amount likely to be securitized),675
adjusted to reflect current conditions and current cost levels.676 This recommended accrual was
calculated by ETI witness Gregory Wilson using a Monte Carlo simulation of ETI’s loss history.677
A statistical distribution was estimated from ETI’s trended loss experience, and the model indicated
an average annual loss of $4,890,000. Mr. Wilson excluded losses from Hurricanes Rita, Gustav,
and Ike from the model because those losses were securitized and not recovered through the
insurance reserve.678 ETI adds that results from the model simulation were also adjusted by
removing any simulated year in which the total storm loss exceeded $100 million, which would
likely be securitized.


           The second component of the proposed annual accrual is $3,870,000 per year for 20 years to
restore the reserve from the current deficit of $59,799,744 up to the $17,595,000 requested target
level. In ETI’s opinion, a 20-year period balances the interests of future and past ratepayers. It




675
      ETI Ex. 19 (McNeal Direct) at 32.
676
      ETI Ex. 14 (Wilson Direct) at 5.
677
      Id. at Ex. GSW-3.
678
      Id. at 9.
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added that Mr. Wilson’s calculations were prepared in accordance with generally accepted actuarial
procedures, with certain adjustments to reflect the nature of ratemaking for public utilities.679


           ETI also requests a target reserve of $17,595,000. It argues that this would be an actuarially
sound provision to cover self-insured losses. ETI noted that the target reserve was also developed
by Mr. Wilson through the Monte Carlo simulation based upon the ETI’s loss history.680


           Cities recommend maintaining the current target reserve of $15,572,000 and adopting an
annual storm damage accrual of $6,150,399. Cities’ proposed annual accrual is comprised of two
parts: (1) keeping the current accrual of $3,650,000 for projected annual storm expense; and
(2) adding $2,500,399 annually to bring ETI’s reserve deficit amount, as adjusted by Cities, up to a
target reserve of $15,572,000. Cities’ witness Jacob Pous testified that the current target reserve of
$15,572,000 should be maintained given ETI’s plan to divest itself of the transmission system,
which would reduce storm damage expenses.681 For the same reason, Mr. Pous also stated that the
Commission should maintain the current annual accrual amount that was approved most recently in
Docket No. 37744.682


           According to Cities, ETI witness Wilson acknowledged that his calculations assumed that the
current transmission system would be owned by ETI, and if the transmission system were sold, his
analysis would need to be adjusted.683 Cities also note that Mr. Wilson included ETI’s 1997 ice
storm expenses within the historical storm data used for his calculations.684 As discussed in
Section V.F., Cities challenge these expenses. If the Commission determines that those costs should
be excluded, Mr. Wilson agreed that it would be inappropriate to include them in his analysis.685 In
addition, Cities stated, Mr. Wilson’s Monte Carlo model analysis has been rejected in several cases

679
      ETI Ex. 14 (Wilson Direct) at 11-12.
680
      Id. at 9.
681
      Cities Ex. 5 (Pous Direct) at 65-66.
682
      Id. at 66; see also Docket No. 37744, Final Order at FoF 31 (Dec. 13, 2010).
683
      Tr. at 1247.
684
      Tr. at 1244-1246.
685
      Tr. at 1246-1247.
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by the Commission, as noted by Staff witness Chris Roelse.686 Cities noted that Mr. Wilson limited
the storm reserve expense in his model to $100 million, as anything over that amount might be
securitized.687 But, Cities contend, Mr. Wilson did not consider that the storm loss history provided
to him by ETI included only storm damage expenses and not capital costs, which are also included
when determining the amount capable of being securitized. Thus, in Cities opinion, Mr. Wilson’s
cap of $100 million was overstated, and for all these reasons Cities argues that Mr. Wilson’s analysis
should not be considered reliable.


          Finally, Cities note that ETI requested that the annual storm reserve accrual “would be made
. . . only until it reaches the recommended target level, at which point contributions to the reserve
would reduce to the lower of annual expected losses or actual losses.”688 In Cities view, this request
should be rejected and the accrual should only be modified through a future rate case.


          OPC also recommends adjustments to the storm damage reserve and the annual accrual. As
discussed in Section V.F., OPC argues that ETI failed to prove that its storm damage expenses
booked since 1996 were reasonable and prudently incurred. Consequently, OPC recommends
disallowing all of those charges. Removing those charges would leave ETI with a positive storm
reserve balance of $41,871,059, which exceeds the currently approved storm reserve balance of
$15,572,000 by $26,299,059. OPC witness Benedict proposed that this surplus be refunded to rate
payers at a rate of $1,314,953 per year for 20 years. He also recommended that current annual storm
damage accrual of $3,650,000 be maintained, less his proposed customer refund of $1,134,953 per
year, leaving a net annual storm damage accrual of $2,335,047 per year.                 Mr. Benedict
acknowledged that some storm damage expenses incurred by ETI since 1996 likely were reasonable
and necessary. Therefore, as an alternative proposal, Mr. Benedict suggested that ETI’s current
storm balance reserve be set at the last approved amount of $15,572,000 (i.e., without any surplus or
deficit) and that the currently approved total annual accrual of $3,650,000 be maintained. In



686
      Staff Ex. 4 (Roelse Direct) at 12.
687
      ETI Ex. 14 (Wilson Direct) at 9.
688
      ETI Initial Brief at 151.
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addition, OPC argues that Mr. Wilson’s Monte Carlo model analysis was flawed because it included
expenses that ETI did not establish were reasonable and prudently incurred.689


          Staff witness Chris Roelse agreed that ETI’s proposed target reserve of $17,595,000 is
reasonable. However, he recommended an annual accrual of $8,270,000, which is $490,000 less
than ETI’s request. Mr. Roelse pointed out that ETI’s witness calculated the proposed annual
accrual based on a Monte Carlo simulation, which projects a loss experience over a longer time than
the period captured in the available loss history. However, Mr. Roelse stated, the Commission has
not approved the use of these models in prior dockets; instead, it has relied on averaging known
insurance losses over a period of time to compute the annual accrual. Using historical loss data,
Mr. Roelse calculated an annual expected storm loss of approximately $4,400,000. When this
amount is added to the proposed annual accrual of $3,870,000 to restore the reserve balance from its
current deficit, it produces a total annual accrual of $8,270,000, which Staff recommends.690


          In response, ETI agreed that if portions of the underlying costs upon which the Monte Carlo
analysis was performed are removed from the reserve, then the outcome of Mr. Wilson’s analysis
would be different. However, ETI stressed that questions about the underlying expenses are not an
attack on the Monte Carlo analysis itself. Rather, Mr. Wilson provided an analysis based upon
information supplied by ETI, and he did not claim to support the expenses themselves. But ETI
disagreed with the challenges to the underlying costs, as discussed in Section V.F.691


          Most of Cities’ and OPC’s objections to ETI’s requested storm damage annual accrual and
target reserve relate to their objections to the underlying expenses, as discussed in Section V.F. For
the reasons stated in that section, the ALJs denied those objections, and they do not support rejecting
ETI’s request for the annual accrual or target reserve. Likewise, the ALJs find that Cities’ concerns
about ETI selling its transmission system are too uncertain to justify altering the storm damage
reserve at this time.


689
      OPC Ex. 6 (Benedict Direct) at 6-16; OPC Initial Brief at 14-20; OPC Reply Brief at 13-15.
690
      Staff Ex. 4 (Roelse Direct) at 10-15; Staff Initial Brief at 13-14.
691
      ETI Reply Brief at 81.
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       Cities also raised a question about whether Mr. Wilson properly calculated the cap he used to
exclude from his analysis storms that would likely result in securitized costs. Staff pointed out that
the Commission has not approved the use of the Monte Carlo simulation model in prior dockets.
Rather, the Commission has traditionally used known insurance losses over a period of time. The
ALJs note that neither PURA nor the Commission’s rules either require or prohibit the use of
actuarial models, such as the Monte Carlo simulation. The prior dockets cited by Staff did not adopt
the recommendations developed by actuarial models, but the Commission also did not expressly
reject the models in those cases. Likewise, however, ETI has not cited any Commission decisions
that expressly adopted or used such models.


       Staff witness Chris Roelse explained that the Commission has traditionally averaged known
insurance losses over a period of time to compute the annual accrual. He made such a calculation
that produced an annual accrual for storm damage loss of $4,400,000. When added to the proposed
annual accrual of $3,870,000 to restore the reserve balance from its current deficit, the total annual
accrual equals $8,270,000. No party challenged that calculation. Because a question remains as to
whether Mr. Wilson properly calculated his cap to exclude storm damage expenses that would likely
be securitized, the ALJs find it is more reasonable to adopt the annual accrual proposed by Staff.
Therefore, the ALJs recommend that the Commission approve a total annual accrual of $8,270,000,
comprised of an annual accrual of $4,400,000 to provide for average annual expected storm losses,
plus an annual accrual of $3,870,000 for 20 years to restore the reserve from its current deficit. The
ALJs also recommend approval of ETI’s proposed target reserve of $17,595,000. Finally, the ALJs
recommend that the Commission require ETI to continue recording its annual accrual until modified
by an order in a future rate case, as requested by Cities. Otherwise, ETI could continue to receive
rates based on the total accrual amount, but not record the receipts in the storm damage reserve. The
ALJs find that such circumstances would not result in just and reasonable rates.


L.     Spindletop Gas Storage Facility

       Cities challenged ETI’s use of the Spindletop Facility, arguing that the costs of operating it
outweigh the benefits gained from it. In Section V.H., the ALJs rejected Cities’ contention that a
substantial portion of ETI’s annual costs to operate the Spindletop Facility should be removed from
SOAH DOCKET NO. XXX-XX-XXXX                    PROPOSAL FOR DECISION                           PAGE 194
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ETI’s rate base. For the same reason he challenged the Spindletop Facility costs associated with rate
base, Cities witness Nalepa also challenges a portion of ETI’s costs derived from the Spindletop
Facility that are associated with operating expenses. Specifically, Mr. Nalepa and Cities argue that
$2,090,116 (consisting of $309,751 in depreciation expense and $1,780,365 associated with the
Spindletop Facility) ought to be removed from ETI’s operating expenses.692 For the same reason
that they rejected Cities’ Spindletop Facility arguments relevant to rate base, the ALJs also reject
Cities’ Spindletop Facility arguments relevant to operating expenses.


 VIII.      AFFILIATE TRANSACTIONS [Germane to Preliminary Order Issue No. 3]

          PURA requires that more stringent standards be applied to affiliate expenses than are applied
to other utility company expenses. Section 36.058 begins by stating “except as provided by
Subsection (b),” the PUC may not allow as capital cost or as expense a payment to an affiliate for
the cost of a service, property, right, or other item or interest expense. Subsection 36.058(b)
provides that the Commission may allow an affiliate payment “only to the extent” that the PUC finds
the payment is reasonable and necessary for each item or class of item as determined by the
Commission.


          The seminal case interpreting PURA’s affiliate transaction standard under Section 36.058 is
Railroad Commission v. Rio Grande Valley Gas Company.693 In that case, the court recognized that
PURA’s affiliate transaction statute created a presumption that a payment to an affiliate is
unreasonable. The court explained:


          Rio’s entire approach has been that the Commission is required to allow the residual
          affiliate charges unless they are shown to be imprudent, unreasonable, or out of line.
           Although this may be true with respect to arms length transactions, it is not true with
          respect to affiliates about which the Legislature has its suspicion and which to any
          reasonable mind are clearly tainted with the possibility of self-dealing.




692
      Cities Ex. 6 (Nalepa Direct) at 19; Cities Initial Brief at 76.
693
      683 S.W. 2d 783 (Tex. App.—Austin 1985, no writ).
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         The court went on to state that the burden was upon Rio to show that its affiliate charges
were just and reasonable. The court interpreted the PURA affiliate transaction statute and explained
four major areas in which Rio had failed to meet its burden of proof:


x     Plaintiff had the burden of showing that the prices it was charged by its affiliate were no higher
      than the prices charged by the supplying affiliate to its other affiliates. . . .

x     Plaintiff had the burden of showing that expenses which may not be allowed for rate making
      purposes for any reason . . . were not included in the “allocated expenses.” . . .

x     Plaintiff had the burden of proving that each item of allocated expense was reasonable and
      necessary. . . .

x     Plaintiff had the burden of proving that the allocated amounts reasonably approximated the
      actual cost of services to it. . . .

         In 2000, the Third Court of Appeals once again spoke on the issue of affiliate transactions in
the utility setting.    In Central Power and Light Company/Cities of Alice v. Public Utility
Commission, the court cited to Rio Grande Valley Gas Company and stated:


         Because of the possibility for self-dealing between affiliated companies, however,
         expenses paid to an affiliated entity are presumptively not included in the rate base.
         A utility can overcome this presumption against affiliate expenses only if it
         demonstrates that its payments are ‘reasonable and necessary for each item or class
         of items as determined by the commission.’694

PURA Section 36.058 places a greater burden of proof on the utility to prove the reasonableness and
necessity of its affiliate transactions because of the nature of the relationship between the utility and
its affiliates. These transactions are not considered to be arms-length, and there is a potential for
self-dealing. The transactions must be disallowed for regulatory purposes, unless the utility presents
sufficient evidence that it has met each of the affiliate transaction statutory requirements. If the
regulatory tests for affiliate transactions are not properly enforced, the regulated utility may become
a vehicle for cross-subsidization by ratepayers of other regulated or unregulated affiliates.



694
      36 S.W.3d 547 at 564 (Tex. App.—Austin 2000, pet. denied) (citations omitted).
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          OPC witness Szerszen was the only witness to challenge ETI’s affiliate transactions,695
recommending a total affiliate disallowance (after erratas) of $8,945,221.696 Dr. Szerszen reviewed
a select subset of ETI’s affiliate expenses using the PURA affiliate transaction standards. She
reviewed the Company’s affiliate transactions on a project by project basis, noting that such a review
was more efficient and easier to understand.697 Dr. Szerszen testified that a review by the
Company’s 25 classes of service presents a far too macro view of affiliate transactions that does not
allow an adequate review of ETI’s affiliate transactions according to PURA mandates and takes the
focus away from the important issues.698


          OPC notes that PURA Subsection 36.058(f) requires that if the Commission finds an affiliate
expense for the test period to be unreasonable, then the Commission is to make a determination of
what level of the expense is reasonable. By analyzing ETI’s affiliate transactions on a project basis,
OPC contends that it has facilitated the Commission’s ability to make such a determination for each
of ETI’s classes of service; instead of an “up or down” decision on the macro level of expense for
the class, the Commission can disallow the portion not shown to be reasonable and approve the
remainder as reasonable.


          ETI disagrees with OPC’s contentions and argues that Dr. Szerszen’s approach to addressing
the Company’s affiliate case is inappropriate for a number of reasons and should be rejected.


x     First, her approach is directly contrary to the Commission’s Guiding Principles included as part
      of the Commission’s Transmission and Distribution Cost of Service Rate Filing Package that
      was issued on April 2, 2003.699 Item 2 of the Guiding Principles clearly states that a class of

695
     Cities witness Mark Garrett recommended disallowance of certain short-term incentive compensation
affiliate costs, but those disallowances are largely also recommended by Dr. Szerszen. See ETI Ex. 69
(Tumminello Rebuttal) at 17. ETI contends that the duplicated disallowances by Dr. Szerszen and Mr. Garrett
would result in double counting $217,520 of the requested affiliate charges and requests that if the ALJs rule
in OPC’s and Cities’ favor regarding these short-term incentive compensation costs, that disallowance should
be reduced by $217,520. ETI Initial Brief at 157, n. 898.
696
      Tr. at 1607.
697
      OPC Exhibit No. 1 (Szerszen Direct) at 42-43.
698
      OPC Exhibit No. 1 (Szerszen Direct) at 42-43; Tr., at 1671-72.
699
      See ETI Ex. 69 (Tumminello Rebuttal) at Ex. SBT-R-1.
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      service approach is required for purposes of complying with the provisions of Section 36.058 of
      PURA.700 Dr. Szerszen ignores the class of service approach required by Section 36.058 of
      PURA as detailed in the Guiding Principles, and instead states OPC’s case on a project code-by-
      project code basis.

x     Second, Dr. Szerszen’s approach is directly contrary to the Commission’s directives in Docket
      No. 16705. In that docket, the Commission disallowed a substantial amount of affiliate expense
      because Entergy Gulf States, Inc. had done then what Dr. Szerszen proposes here – based the
      affiliate analysis solely on project codes, rather than affiliate classes of service. Because the
      Commission found that a scope statement/project code-based affiliate analysis is “impossible,”
      the Company, in its subsequent base rate cases, including its filing in this docket, changed to a
      class-based presentation, as directed by the Commission.

x     Third, by refusing to consider a class-based analysis, Dr. Szerszen has ignored the Company’s
      testimony, presented by 19 affiliate witnesses, which explains in detail why the Company’s
      affiliate-incurred costs meet the Section 36.058 of PURA and Rio Grande standards.701
      According to ETI, the Company’s affiliate class witnesses, who are knowledgeable about the
      activities that are encompassed in each of their classes, have each shown why the services
      provided through those classes are necessary. They have each also addressed numerous
      Commission-recommended metrics to measure the reasonableness of costs, including cost
      trends, staffing trends, the budgeting process, and, if applicable, benchmarking and outsourcing
      comparisons.702 Their testimony and exhibits, according to ETI, show numerous different
      “views” of the costs in their classes, including the project codes that comprise their classes.
      Each affiliate witness also addressed the “not higher than” and “reasonably approximates cost”
      standards applicable to affiliate costs. ETI contends that the evidence provided by its witnesses
      meets the requirements of these Guiding Principles and supports the Company’s burden of proof
      for the recovery of affiliate costs. ETI also contends that Dr. Szerszen ignores this overwhelming
      evidence and the careful attention paid to presenting it in an organized manner. In addition, she
      presents no evidence in accordance with the Guiding Principles that supports her proposed
      disallowances.

x     Fourth, the Company’s case is much less cumbersome and less complex than the approach
      suggested by OPC, which would require a showing on the necessity, reasonableness, “not higher
      than,” and “reasonably approximates cost” standards for each of almost 1,300 project codes
      subject to this docket. Even if the Company were to do that, Dr. Szerszen’s “cherry picking”
      approach among the project codes ignores any savings in other project codes that would

700
    Dr. Szerszen conceded that the Guiding Principles require that a utility’s affiliate case be presented in a
sufficient number of class or other logical groupings. Tr. at 1632.
701
   Dr. Szerszen claimed that, instead of considering the narrative class testimony, she instead “looked at
more of the detail,” presumably meaning the exhibits. Tr. at 1629.
702
   ETI Ex. 69 (Tumminello Rebuttal) at Ex. SBT-R-1. Dr. Szerszen conceded that the Company’s testimony
included proof items such as benchmarking data, outsourcing, staffing trends, and cost trends. Tr. at 1631.
SOAH DOCKET NO. XXX-XX-XXXX                PROPOSAL FOR DECISION                                PAGE 198
PUC DOCKET NO. 39896


      comprise a class of affiliate costs, thereby resulting in an overall reasonable level of costs within
      the class even assuming that any of her complaints about individual project codes had merit.

x     Fifth, ETI contends that Dr. Szerszen fails to mention Section 36.058(f) of PURA, which
      requires that the Commission determine the reasonable level of “an affiliate expense” if it first
      finds that the expense presented is unreasonable. But rather than offering an alternative
      “reasonable” level of an expense“”, she either categorically disallows all costs in that project; or,
      in some instances, substitutes an arbitrary sharing or allocation of costs between ETI and its
      regulated affiliates, or ETI and its non-regulated affiliates. In doing so, Dr. Szerszen does not
      make any evidence-based attempt to ground her alternative allocation (and associated
      disallowance of ETI affiliate costs) on any objective basis reflecting cost causation principles.
      ETI contends that the effect of her approach is to presume that the Company needs zero dollars
      in its cost of service to perform a variety of essential utility support activities.

x     Sixth, Dr. Szerszen’s positions in the 2009 Oncor rate case,703 which she agrees are similar to
      her positions in this ETI base rate case,704 were rejected by the two SOAH ALJs and the
      Commission in that docket. ’’Many of the allegations and arguments made by Dr. Szerszen in
      this case are very similar, if not identical, to the points she asserted in the Oncor case.

          The ALJs agree that the Commission’s Guiding Principles set forth the minimum that a
utility must present to establish a prima facie case, and it is clear that ETI met that burden. That,
however, is not the end of the question. Permitting a utility to escape further scrutiny of its affiliate
transactions by resting on its prima facie presentation imposes too many limits and, as suggested by
OPC, presents too macro a view to be a legitimate review for rate case purposes.


          OPC performed essentially a sample review of ETI’s affiliate transactions. The review was
not exceptionally large, and (as evidenced by ETI’s concurrence in the removal of some of the costs)
it represented an additional layer of review to ensure that improper costs would not inadvertently be
charged to ratepayers. That, of course, is not the sole focus of OPC’s review, but it is important for
purposes of determining whether the review itself is appropriate. If intervenors and Staff were
limited to the macro level of review urged by ETI, such matters would never be revealed and there
would exist a possibility that ratepayers would be charged for matters not their responsibility. The
ALJs do not characterize OPC’s review as “cherry picking.” It is more a reasonable sample for

703
   Application of Oncor Electric Delivery Company, LLC for Authority to Change Rates, Docket No. 35717
(PFD issued on Jun. 2, 2009; Order on Rehearing issued on Nov. 30, 2009) (Oncor).
704
      Tr. at 1656.
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examination that gives ETI a reasonable opportunity to explain the reasons for the charges to
ratepayers. Accordingly, the ALJs find that the Commission’s Guiding Principles do not limit the
review performed by OPC, and the review performed by OPC is not contrary to the Commission’s
holdings in Docket No. 16705.


A.        Large Industrial & Commercial Sales Reallocation

          OPC contends that ETI incurs considerable amounts of sales and marketing expenses that are
exclusively for the benefit of the larger commercial and industrial customers. However, most of
ESI’s sales, marketing, and customer service expenses are allocated to residential and small business
customers.705 The vast majority of the sales, marketing and customer service expenses are allocated
to the operating companies based on customer counts, the majority of these expenses are
consequently allocated to residential and small business customers. In the test year, residential and
small general service customers made up 94.8 percent of the ETI total customer count. ETI’s
General Service, Large General Service, and Large Industrial Power Service, and Lighting classes
combined comprise only 5.2 percent of ETI’s customers. For the test year, OPC argues that ETI is
requesting the recovery of $2.086 million of sales, marketing, billing and load research expenses that
benefitted only the large customer service classes. OPC contends that it is inappropriate for
residential and small customers to pay for these expenses, when cost causation is so readily
identifiable, particularly since a disproportionately small portion of larger customer sales and
marketing expenses is allocated to ETI’s largest customers.706 The total recommended reallocated
large customer expense is $2,086,145.


          ETI and TIEC oppose OPC’s recommendation, arguing that it is “cherry-picking” and that
the evidence does not demonstrate that the $2.086 million of affiliate expense should be directly
assigned to the large commercial and industrial classes.707




705
      OPC Ex. 1 (Szerszen Direct) at 45.
706
      OPC Ex. 1 (Szerszen Direct) at 45.
707
      ETI Ex. 55 (LeBlanc Rebuttal) at 5; TIEC Ex. 3 (Pollock Cross Rebuttal) at 36.
SOAH DOCKET NO. XXX-XX-XXXX                 PROPOSAL FOR DECISION                             PAGE 200
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          With respect to the first argument, ETI and TIEC contend that Dr. Szerszen developed her
adjustment by examining a limited sample of affiliate project code summaries and making the call,
based on project code descriptions, that certain affiliate costs for marketing, sales and customer
service expense should be directly assigned to large commercial and industrial customers.708 Both
TIEC and ETI contend that the bias and results-oriented nature of her recommendation became
apparent when Dr. Szerszen admitted on cross examination that she made no effort to examine
whether certain affiliate costs should be directly assigned to residential and small customers.709
Both ETI and TIEC contend that it is inappropriate to take a “limited sample of costs” and directly
assign them to a particular class.


          According to TIEC, Dr. Szerszen admitted that it could have been appropriate to make an
adjustment for direct assignment of costs to small commercial and residential customers based on
principles of cost causation.710 However, she made no effort to do that herself, nor did she ask ETI
to conduct such an analysis.711 The parties argue that the evidence shows that Dr. Szerszen’s
recommendation rests on an incomplete analysis of ETI’s affiliate costs and her recommendation
should be rejected because direct assignment of costs is only appropriate if there has been a thorough
and complete cost study analysis to determine what costs are or are not appropriate for direct
assignment to all of the classes.


          TIEC further argues that the evidence did not demonstrate that the $2.086 million of affiliate
expense that Dr. Szerszen proposes for direct assignment to large commercial and industrial
customers is solely attributable to costs caused by those customers. Mr. Pollock testified that the
project codes Dr. Szerszen selected include load research expenses that benefit residential and small
commercial customers.712 TIEC pointed out that ETI witness Stokes testified that the billing
methods used for the affiliate expenses for customer service operations and retail operations were


708
      Tr. at 1609.
709
      Tr. at 1609-10.
710
      Tr. at 1685.
711
      Tr. at 1613-1624.
712
      TIEC Ex. 3 (Pollock Cross Rebuttal) at 35.
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fair and reasonable.713 According to TIEC, Dr. Szerszen’s proposal should be rejected because her
assertion that these expenses exclusively benefit large commercial and industrial customers is
incorrect.


          The ALJs have reviewed the arguments of the parties and find that Dr. Szerszen’s analysis is
far from complete. It appears to be result-oriented, ignoring critical aspects (such as failing to make
an adjustment for direct assignment of costs to small commercial and residential customers based on
principles of cost causation). The ALJs believe that Dr. Szerszen’s analysis with respect to this issue
should not be adopted.


B.        Administration Costs

          Dr. Szerszen recommended disallowance of $94,709 (25 percent) of the charges in
Project F3PCFACALL, contending that ESI failed to directly charge any of the costs in this project
code to ETI. She claimed that the billing method applied to this project code by ESI (that is, Billing
Method “SQFALLC”), which is based on square footage, is not appropriate for these types of
costs.714


          ETI witness Plauche explained that the costs captured in this project code are primarily for
the oversight of administrative functions, such as facilities, real estate, and security.715 This project
code applies to the administration of these types of functions. These services benefit all companies
that receive facility services and are not attributable to any one specific Entergy affiliate. Therefore,
it is appropriate to bill these costs to all companies based on their pro rata share of square footage
occupied.716


          The ALJs concur that this is the appropriate method to employ and, therefore, recommend
that the Commission approve the inclusion of these costs as requested by ETI.

713
      ETI Ex. 66 (Stokes Rebuttal) at 3.
714
      OPC Ex. 1 (Szerszen Direct) at 80-82.
715
      ETI Ex. 20 (Plauche Direct) at 15-26.
716
      ETI Ex. 69 (Tumminello Rebuttal) at Ex. SBT-R-2 at 10.
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C.        Customer Service Operations Class

          Dr. Szerszen recommended disallowances in seven project codes covered primarily by ETI’s
Customer Service Operations Class: (1) F3PCR29324 (Revenue Assurance - Adm.) for a
disallowance of $70,849; (2) F3PCR53095 (Headquarter’s Credit & Collect) for a disallowance of
$110,338; (3) F3PCR73380 (Credit Systems) for a disallowance of $73,562; (4) F3PCR73458
(Credit Call Outsourcing) for a disallowance of $197; (5) F3PCR73381 (Customer Svc Cntr Credit
Desk) for a disallowance of $43,378; (6) F3PCR73390 (Customer Svs Ctl - Entergy Bus) for a
disallowance of $60,926; and (7) F3PCR73403 (Customer Issue Resolution – ES) for a disallowance
of $1,869.717


          1. Projects F3PCR29324 (Revenue Assurance - Adm.), F3PCR53095 (Headquarter’s
             Credit & Collect), F3PCR73380 (Credit Systems), and F3PCR73458 (Credit Call
             Outsourcing)

          For the costs captured by these project codes, Dr. Szerszen recommended that the costs be
reallocated based on the Company’s 10 percent “bad debt” expense percentage.


          ETI witness Stokes responded that the costs captured by these project codes are for
management and supervision of credit, collection, and revenue assurance activities for all of the
Operating Companies. These functions ensure the most efficient processes are used in managing
write-offs for all the Operating Companies and have contributed to Entergy’s first quartile ranking in
benchmarking of credit and collection operations. These managerial and supervisory costs, which
include bankruptcy administration, surety administration, arrears management, collection agency
administration, skip tracing, and final bill collections, remain consistent whether ETI’s bad debt
percentage is 10 percent, 30 percent, or any other percent and are appropriately allocated using the
CUSTEGOP billing method, which is based on the number of electric and gas customers for each
Operating Company.718




717
      OPC Ex. 1 (Szerszen Direct) at 76-78.
718
      ETI Ex. 66 (Stokes Rebuttal) at 15-16.
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       ETI has provided credible evidence that it has chosen the correct billing methodology.
Therefore, the ALJs recommend the Commission approve inclusion of these costs as requested by
ETI.


       2. Projects F3PCR73381 (Customer Svc Cntr Credit Desk), F3PCR73390 (Customer
          Svs Ctl - Entergy Bus), and F3PCR73403 (Customer Issue Resolution – ES)

       Dr. Szerszen recommended that these costs be reallocated using the CUSTCALL billing
method. Given ESI’s demonstrated tracking capabilities, Dr. Szerszen reallocated the costs of this
project using a 10.8 percent customer call allocator, which is on the low end of the
10.70 percent-11.04 percent Test-Year CUSTCALL allocators.719


       ETI witness Stokes believes that Dr. Szerszen’s proposed reallocation is arbitrary and fails to
consider the cost causation associated with the actual project code at issue. These costs are not
driven by a specific proportion of calls from each Operating Company (that is, by the CUSTCALL
allocator). The costs captured by Project F3PCR73345 reflect the costs of overseeing the Quick
Payment Center vendors in each of the Entergy Operating Companies, regardless of the number of
calls by customers to the Company.


       The ALJs are persuaded that the allocation methodology chosen by ETI is the superior
method and that the CUSTCALL allocator would not be appropriate given the cost causation
associated with the project. Accordingly, the ALJs recommend the Commission approve the costs
proposed by ETI.


D.     Distribution Operations Class

       Dr. Szerszen addressed three project codes that are within the Distribution Operations Class:
(1) F5PCDW0200 (Lineman’s Rodeo Expenses) for a disallowance of $7; (2) F3PCTJGUSE (Joint




719
    OPC Exhibit No. 1 (Szerszen Direct) at 77 and 118; OPC Exhibit No. 27 (ETI’s Ex. SBT-15,
Attachment 6) at 2; Tr., at 838-839.
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Use With Third Party – E) for a disallowance of $6,405; and (3) F3PCTJTUSE (Joint Use With 3rd
Parties – A) for a disallowance of $36,293.720


         1. Project F5PCDW0200 (Lineman’s Rodeo Expenses)

         Dr. Szerszen claimed that the expenses captured by this project should be disallowed because
ETI is a monopoly and Texas ratepayers should not have to pay for corporate image costs.


         ETI witness Tumminello responds, stating that this minimal amount is related to a safety
competition known as the “Lineman’s Rodeo,” it is not a corporate “image” expense. The cost,
according to Ms. Tumminello, is driven by Entergy employee safety in the Distribution business
units.721


         The ALJs agree that the Lineman’s Rodeo competition is not a corporate image expense,
rather it is designed to promote employee safety. The ALJs recommend the Commission approve
inclusion of the costs captured by this project as requested by ETI.


         2. Projects F3PCTJGUSE (Joint Use With Third Party – E) and F3PCTJTUSE (Joint
            Use With Third Parties – A)

         Dr. Szerszen recommends exclusion of these two projects, which she claims represent the
difference between the costs incurred for ETI for pole rental costs and the revenues received from
pole space rentals.


         With respect to this proposed disallowance, ETI witness McCulla states that Dr. Szerszen has
confused the rental of space on transmission poles and the rental of space on distribution poles. She
has essentially performed a cost-benefit analysis that erroneously compares the cost of providing
rental space on distribution poles with the income received solely from rental of space on
transmission poles. Mr. McCulla explained that data for the distribution poles show that the more
than $2.5 million in revenues from distribution pole rentals far exceeds the $67,174 in costs billed to

720
      OPC Ex. 1 (Szerszen Direct) at 66, 75.
721
      ETI Ex. 41 (Tumminello Direct) at Ex. SBT-E at 1234.
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ETI under these two project codes and, therefore, Dr. Szerszen’s misassumption that the revenues
were less than the costs incurred is unfounded.722


           The ALJs find that Dr. Szerszen erred. Making the correct comparison, as demonstrated by
Mr. McCula, shows there is no basis for the disallowance claimed by Dr. Szerszen. The ALJs,
therefore, recommend the Commission deny the requested disallowance.


E.         Energy and Fuel Management Class

           Dr. Szerszen addresses seven project codes that are within the Energy and Fuel Management
Class: (1) F3PCCSPSYS (System Planning And Strategic) for a disallowance of                   $29,304;
(2) F3PCWE0140 (EMO Regulatory Affairs) for a disallowance of $114,468; (3) F3PPSPE002
(SPO 2009 Renewable RFP Expense) for a disallowance of $3,014; (4) F3PPSPE003 (SPO Summer
2009 RFP Expense) for a disallowance of $56,672; (5) F3PPSPE004 (SPO Summer09RFP
IM&Propslsubmt) for a disallowance of $42,018; (6) F3PPWET300 (SPO 2008 Western Region
RFP-Te) for a disallowance of $645; and (7) F3PPWET303 (SPO2008WinterWestnRegionRFP-IM)
for a disallowance of $4,200.723

           1. Project F3PCWE0140 (EMO Regulatory Affairs)

           Dr. Szerszen testified that Texas ratepayers do not receive benefits as a result of the costs
captured by this project code and should therefore not be charged those costs.724

           ETI witness Cicio explained that Dr. Szerszen misinterpreted an RFI response to conclude
that Texas ratepayers did not receive benefits from the activities whose costs were booked through
this project code. That project code is not intended to capture costs for docketed or large System
Planning and Operations projects. Mr. Cicio states that it is not possible to assign a specific project
code for every discrete activity performed by each employee, nor would it be appropriate to attempt
to do so. Regardless of the number of activities specifically identified through project codes, there

722
      ETI Ex. 59 (McCulla Rebuttal) at 8-12.
723
      OPC Ex. 1 (Szerszen Direct) at 55, 60, and 65-66.
724
      Id. at 55.
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will remain the need to have generic project codes that capture time spent on more general,
undocketed matters and activities that are no less beneficial to ratepayers.725

          The ALJs agree that Texas ratepayers receive benefits as a result of the costs charged to this
account. Accordingly, the ALJs recommend the Commission approve inclusion of the costs as
requested by ETI.

          2. Projects F3PPSPE003 (SPO Summer 2009 RFP Expense), F3PPSPE003 (SPO
             Summer 2009 RFP Expense), F3PPSPE004 (SPO Summer09RFP IM &
             Propslsubmt), and F3PPWET303 (SPO2008 Winter Westn RegionRFP-IM)

          Dr. Szerszen testified that the costs captured by these projects should be disregarded because
they were incurred during the 2008-2009 period, which is outside of the Test Year, and are
nonrecurring.726


          ETI witness Cicio explained that although these projects were initiated prior to the Test Year,
the costs that the Company seeks to recover through these project codes were expenses incurred
during the Test Year, including development activities, request for proposal issuance, bidders
conferences, written and posted questions and answers from market participants and other interested
parties, submission of proposals, screening of proposals, proposal evaluation, follow-up questions
and clarifications, recommendations and awards, contract negotiations, Independent Monitor reports,
and regulatory approvals, if necessary. These routinely encompass a multi-year time frame, and the
costs required to perform those activities, although associated with a project that may have been
initiated several years previously, are properly incurred over the life span of the project. He also
states that they are recurring because they reflect the kinds and levels of charges that would be
expected to be incurred on an ongoing basis in association with requests for proposals managed by
ESI on behalf of the Entergy Operating Companies, and the Company has been involved in these
types of solicitations since 2002.727



725
      ETI Ex. 45 (Cicio Rebuttal) at 8-9.
726
      OPC Ex. 1 (Szerszen Direct) at 65.
727
      ETI Ex. 45 (Cicio Rebuttal) at 13-14.
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          The ALJs find that the costs captured by these projects were incurred during the Test Year
and represent the kinds and levels of costs routinely incurred on a recurring basis. Accordingly, the
ALJs recommend that the Commission approve their inclusion as requested by ETI.


          3. Project F3PCCSPSYS (System Planning and Strategic)

          Dr. Szerszen recommended total disallowance of the costs captured by this project code
because they are allocated based on the total assets of the Entergy affiliates.728 Dr. Szerszen’s
conclusion appears to be that no such corporate-level costs should be allocated to ETI because there
are other project codes that allocate corporate planning and analysis-type costs only to the regulated
utilities, such as ETI; thus, any corporate-level costs that are allocated to all subsidiaries, whether
regulated or non-regulated, should not be charged to ETI.


          ETI witness Tumminello testified that Dr. Szerszen’s theory neither considers the Entergy
organization as a family of companies and ETI’s place in that family, nor the fact that these services
are not only relevant to ETI as part of the Entergy family, but are reasonable, necessary and meet the
Commission’s affiliate cost recovery standard. ESI’s corporate oversight services are provided to
both individual companies and groups of companies within the Entergy ’corporate structure. As a
member of the corporate group, ETI receives the benefit of corporate-level planning, reporting, and
forecasting activities provided by ESI.729


          The ALJs find that ETI (and, therefore, its ratepayers) does receive benefits as a member of
the Entergy family of companies and that it is appropriate for it to receive charges for those services.
Therefore, the ALJs recommend the Commission approve the inclusion of costs as requested by ETI.


F.        Environmental Service Class

          Dr. Szerszen recommended disallowance of $301,879 in six project codes primarily within
ETI’s Environmental Services Class: (1) F3PCCE0129 (Corporate Sustainability Strat) for a


728
      OPC Ex. 1 (Szerszen Direct) at 60-61.
729
      ETI Ex. 69 (Tumminello Rebuttal) at 10-11.
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disallowance of $6,781; (2) F3PCCE0193 (Corp Environmental Special Pro) for a disallowance of
$1,203; (3) F3PCCEIE01 (Corp Environmental Initiatives) for a disallowance of $2,413;
(4) F3PCCEII01 (Corp Environmental Initiatives) for a disallowance of $2,413; (5) F3PCCEP001
(Corporate Environmental Policy) for a disallowance of $269,248; and (6) F5PPBCNAVF (Avian
Flu Contingency Planning) for a disallowance of $47.730


            Dr. Szerszen’s reasoning for this disallowance was that these six project codes, which all
deal with corporate environmental policy, initiatives, strategy, and consulting services, were
allocated based on Billing Method CAPAOPCO, which is based on the fossil plant capacity of the
regulated utility operating companies, even though “non-regulated entities clearly benefit from the
corporate level expenses.”731               Dr. Szerszen recommended a $47 disallowance for
Project F5PPCCNAVF (Avian Flu Contingency Planning), asserting that this charge is a “corporate
imaging expense that should not be borne by Texas ratepayers.”732


            According to ETI, Dr. Szerszen has a fundamental misunderstanding of how the affiliate
billing system works and, as a result, she incorrectly assumed that ESI charges are not being
properly allocated. ETI argues that the non-regulated Entergy affiliates do receive the proper and
appropriate allocation of costs. The two service companies for non-regulated affiliates also provide
services to their non-regulated affiliates directly. There simply is no subsidization or improper
allocation.733


            Dr. Szerszen noted that Entergy’s website indicates that nuclear-related environmental issues
are being pursued.734 She argued that this shows that the non-regulated affiliates are under-allocated

730
      OPC Ex. 1 (Szerszen Direct) at 62-63.
731
      Id.
732
      Id. at 66.
733
     See, e.g., ETI Ex. 41 (Tumminello Direct) at 10-15. Moreover, while ESI bills the regulated utility
affiliates such as ETI at cost, it bills the non-regulated affiliates at cost plus a 5 percent mark-up pursuant to a
June 1999 Securities and Exchange Commission order. ETI Ex. 41 (Tumminello Direct) at 15. This
5 percent mark-up is then flowed back to entities that receive service from ESI. Therefore, the regulated
affiliates are, by federal order, receiving essentially a rebate from the non-regulated affiliates.
734
      OPC Ex. 1 (Szerszen Direct) at 62.
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environmental-related costs. Ms. Stokes explained that the project codes at issue “deal with services
provided to the operating companies. . . . and just looking at the website there are other things . . .
that are not covered or paid for by Texas ratepayers in these project codes that are in this
testimony.”735 Therefore, according to Ms. Stokes, these project codes are not allocated in such a
way that under-recovers costs from the non-regulated affiliates; they pay their own way.


          Finally, the Project Summary for the Avian Flu Contingency Planning project shows that
these costs involve developing and communicating Avian Flu business continuity plans and then
maintaining, checking, and adjusting those plans once established.736 These are not “corporate
imaging expenses” as characterized by Dr. Szerszen.


          The ALJs agree that ETI’s evidence demonstrates the recoverability of the costs captured by
these project codes. Therefore, the ALJs recommend the Commission approve their recovery.


G.        Federal PRG Affairs Class

          Dr. Szerszen recommended disallowances for three project codes primarily in the Federal
PRG Affairs Class: (1) F5PPSPE044 (PMO Support Initiative-System) for a disallowance of $344;
(2) F3PPUTLDER (Utility Derivatives Compliance) for a disallowance of $20,447; and
(3) F3PCSYSRAF (System Regulatory Affairs-Federal) for a disallowance of $352,084.737


          1. Project F5PPSPE044 (PMO Support Initiative-System)

          Dr. Szerszen recommended disallowance of $344.29 from Project F5PPSPE044 (PMO
Support Initiative System). ETI responds, however, that a review of the Project Summary for that
project code in Ex. SBT-E reveals that ETI already removed those costs before even filing its direct




735
      Tr. at 884.
736
      ETI Ex. 41 (Tumminello Direct) at SBT-E at 1342-43.
737
      OPC Ex. 1 (Szerszen Direct) at 46-47, 66-67.
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case. Therefore, according to ETI, Dr. Szerszen is recommending disallowance of a cost that is not
in this case.738


          The ALJs agree that examination of the exhibit referenced by ETI appears to reveal that the
costs challenged by Dr. Szerszen have been removed from this case through a pro forma adjustment.
Accordingly, the ALJs recommend the Commission reject OPC’s challenge.


          2. Project F3PPUTLDER (Utility Derivatives Compliance)

          Dr. Szerszen recommended disallowance of $20,447 of derivatives expenses because ETI did
not use derivative instruments and therefore should not be charged these costs and because
ratepayers do not benefit from derivatives.739


          ETI witness Tumminello responded that Project F3PPUTLDER was charged by a group
developing compliance mechanisms to protect Entergy’s regulated utility interests in observance of
the Dodd-Frank Act. Although ETI does not currently use any derivative activities, understanding
the impacts of that Act is necessary to ensure current and future compliance through Entergy. The
definitions under the legislation have not been finalized, and there remain issues that ETI must be
aware of to fully comply. These costs, therefore, are necessary and reasonable charges that should
not be disallowed.740


          The explanation offered by ETI for the inclusion of these charges appears reasonable to the
ALJs. Even though ETI does not now use derivatives, it is possible that it will in the future and it is
important that it be aware of the regulatory framework associated with such actions to avoid
problems. The ALJs therefore recommend the Commission approve inclusion of these costs as
requested by ETI.

738
      ETI Initial Brief at 174-175.
739
    ETI stated that it assumes that Dr. Szerszen must be referring to Project Code F3PPUTLDER (Utility
Derivatives Compliance) because her recommended disallowance is the same total ETI adjusted amount
shown on the Project Summary for that project code. See SBT-E at 1113. The ALJs make the same
assumption as it appears reasonable.
740
      ETI Ex. 69 (Tuminello Rebuttal) at Ex. SBT-R-2 at 3.
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           3. Project F3PCSYSRAF (System Regulatory Affairs-Federal)

           In the regulatory affairs category, ETI requests the recovery of various legal,
testimony-related, communications, and filing costs associated with both Texas-specific regulatory
activities, FERC-related regulatory activities, and non-Texas specific regulatory activities. OPC
witness Szerszen did not recommend a disallowance of the $1,442,223 in adjusted Test Year
expenses for regulatory affairs that ETI has shown to be specific to the Texas jurisdiction.741
Rather, Dr. Szerszen recommended that all regulatory affairs expenses not specific to Texas be
disallowed.742 These expenses total $759,868.743


           Project F3PCSYSRAS (System Regulatory Affairs – State) was incurred for administrative
activities for senior management, project work associated with system-wide regulatory matters,
system-wide regulatory strategies and emerging regulatory issues, and it relates to multiple regulated
jurisdictions.744 Project No. F3PCSYSRAF (System Regulatory Affairs – Federal) was incurred for
regulatory oversight and coordination of FERC matters.745 OPC contends that ETI provided no
evidence that Texas ratepayers receive any tangible benefits from “system” regulatory affairs costs
in proportion to the costs being allocated to Texas.


           Project F3PCSYSRAS costs are allocated to the subsidiaries based on electric customer
counts, and OPC states that it is questionable whether Entergy’s positions on “emerging” state or
national regulatory issues or “system-wide regulatory strategies” are conveying any benefits to its
electric customers beyond those already captured in the Texas-specific regulatory affairs project
codes.746 In fact, according to OPC, the Company’s shareholders are the primary beneficiaries of
these system-wide regulatory strategies.747 The federal regulatory affairs costs captured under

741
      See OPC Ex. 3 (Szerszen Workpapers) at 368-371.
742
      OPC Ex. 1 (Szerszen Direct) at 46-47.
743
      Id. at 46.
744
      OPC Ex. 3 (Szerszen Workpapers) at 365.
745
      OPC Ex. 1 (Szerszen Direct) at 46-47; OPC Ex. 3 (Szerszen Workpapers) at 367.
746
      OPC Ex. 3 (Szerszen Workpapers) at 368-371.
747
      OPC Ex. 1 (Szerszen Direct) at 47.
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Project F3PCSYSRAF are allocated to the regulated subsidiaries based on each company’s load
responsibility ratio; this ratio assumes that every FERC docket and/or FERC issue is related to ETI’s
peak demand. According to OPC, this is not reality, nor is it consistent with FERC’s primary
responsibility to ensure that electric wholesale buyers and sellers are provided open access
transmission across utility systems.


          ETI witness May offered the following as rebuttal of Dr. Szerszen’s contentions regarding
these two project codes:


          The affiliate charges to Project Codes F3PCSYSRAS and F3PCSYSRAF are directly
          associated with the issues and matters within the federal jurisdiction of the Federal
          Energy Regulatory Commission (“FERC”) including but not limited to the Open
          Access Transmission Tariff (“OATT”) as well as any other federal statutes, rules and
          regulations. These are the result of issues and matters raised concerning the OATT,
          operations of the transmission system, requests for transmission service and
          interpretation of applicable provisions under the jurisdiction of FERC. They are
          costs incurred on an Entergy System-wide basis that cannot be directly assigned to
          any one Operating Company, such as ETI.748

He then went on to state that the affiliate Test Year issues and costs related to these project codes are
reflective of typical issues and costs that the Company experiences on an ongoing basis.749 With
respect to the benefits derived by Texas ratepayers as a result of activities conducted under these
project codes, Mr. May stated that:


          the benefit to ETI involves a multitude of issues that are directly related to the
          jurisdiction of the FERC, including but not limited to any revisions to Service
          Schedules under the System Agreement that applies to all operating companies
          including ETI, power purchase agreements for cost-based, short-term power sales,
          and compliance with FERC by each Operating Company to the market-based rate
          tariff and cost-based rate tariff. The Entergy Operating Companies’ market-based
          rate tariff and cost-based rate tariff are joint tariffs containing terms and conditions
          of service.750


748
      ETI Ex. 57 (May Rebuttal) at 25.
749
      ETI Ex. 57 (May Rebuttal) at 25.
750
      ETI Ex. 57 (May Rebuttal) at 27-28; see also, Tr. at 370-371.
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Mr. May also explained why the billing methods applied to these two project codes are appropriate.
The cost drivers for Project F3PCSYSRAF are labor, employee expenses, consultant expenses, and
other general operating expenses incurred for the benefit of the Entergy Operating Companies and
their regulated customers.        Therefore, a billing method based on load responsibility –
“LOADOPCO” – is appropriate for this type of project code. Project F3PCSYSRAS captures costs
associated with general regulatory support work that is applicable across all of the jurisdictions. The
primary activities associated in this project code include but are not limited to: special project work
associated with system-wide regulatory matters, analysis of emerging state or national regulatory
and accounting issues affecting the Entergy System, and internal process improvement work. What
drives the cost of this project code is the average number of both electric and gas customers served –
CUSTEGOP – because all such customers benefit from these services provided by ESI to ETI.751 In
short, according to ETI, the activities undertaken under both of these project codes benefit Texas
ratepayers, and they are properly allocated to the regulated operating companies using the billing
methods employed.


          The ALJs believe that resolution of this question is a close call. Although ETI provided an
adequate explanation of the reasons underlying the allocation of costs to Texas ratepayers and the
appropriateness of the allocation methodologies used, the one troubling aspect, as noted by OPC,
was that Mr. May’s testimony regarding Projects F3PCSYSRAF and FP3PCSYSRAS contradicted
the fact that ESI has a specific project dedicated to open access transmission issues entitled “FERC-
Open Access Transmission” (Project F3PCE01601).752 As OPC notes, if Mr. May was correct that
OATT issues have been included in Projects F3PCSYSRAF and FP3PCSYSRAS the project pages
should arguably be more specific about the purpose of the expenditure. Nevertheless, the ALJs find
ETI’s testimony credible and recommend that the costs of Projects F3PCSYSRAF and
FP3PCSYSRAS not be disregarded.




751
      ETI Ex. 57 (May Rebuttal) at 28-29.
752
      OPC Ex. 11; also found in OPC Exhibit No. 3 (Szerszen Workpapers)at 363-364.
SOAH DOCKET NO. XXX-XX-XXXX               PROPOSAL FOR DECISION                             PAGE 214
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H.        Financial Services Class

          Dr. Szerszen recommended disallowances in nine project codes that are primarily captured
within ETI’s Financial Services Class of affiliate costs: (1) F3PCF05700 (Corporate Planning &
Analysis) for a disallowance of $4,254; (2) F3PCF21600 (Corp Rptg Analysis & Policy) for a
disallowance of $320,157; (3) F3PCFF1000 (Financial Forecasting) for a disallowance of $96,734;
(4) F3PPADSENT (Analytic/Decision Support-Entergy) for a disallowance of $93,544;
(5) F3PPSPSENT (Strategic Planning Svcs-Entergy) for a disallowance of $45,265;
(6) F3PCR73345 (Quick Payment Center, Adm) for a disallowance of $14,484; (7) F3PCF20990
(Operations Exec VP & CFO) for a disallowance of $146,267; (8) F3PCFF1001 (OCE Support) for
a disallowance of $1,923; and (9) F3PCF23936 (Manage Cash) for a disallowance of $15,677.753


          1. Projects F3PCF05700 (Corporate Planning & Analysis), F3PCF21600 (Corp Rptg
             Analysis & Policy), F3PCFF1000 (Financial Forecasting), F3PPADSENT
             (Analytic/Decision Support-Entergy), and F3PPSPSENT (Strategic Planning Svcs-
             Entergy)

          Dr. Szerszen proposed to disallow all costs related to these five project codes, which she
collectively describes as addressing Corporate Planning, Reporting, and Forecasting issues because
she contends that an assets-based allocator should not be used to allocate these costs and, regardless
of the allocator used, these types of services do not benefit Texas ratepayers because ESI has, in
other instances, directly billed corporate-level services to ETI.


          ETI witness Tumminello responded, stating that Dr. Szerszen failed to consider the Entergy
organization as a family of companies and ETI’s place in that family. The services provided under
these project codes are not only relevant to ETI as part of the Entergy family, but are reasonable and
necessary. ESI’s corporate oversight services are provided to both individual companies and groups
of companies within the Entergy Companies’ corporate structure. As a member of the corporate
group, ETI receives the benefit of corporate-level planning, reporting, and forecasting activities
provided by ESI. Ms. Tumminello contested that the use of an asset-based allocator is appropriate



753
      OPC Ex. 1 (Szerszen Direct) at 56, 60-62, and 74, and Schedules CAS-9, CAS-10, and CAS-15.
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PUC DOCKET NO. 39896


because this is an example of the stewardship of the company-wide assets and such an allocator is,
therefore, appropriate.754 The ALJs agree.


         The ALJs find that ETI’s proposed allocator is appropriate and that the costs benefit Texas
ratepayers. Accordingly, the ALJs recommend the Commission approve the costs proposed by ETI.


         2. Projects F3PCF20990 (Operations Exec VP & CFO) and F3PCFF1001 (OCE
            Support)

         Dr. Szerszen recommended disallowance of all costs captured by these project codes
because, in her opinion: (1) there are “no perceivable benefits to ETI’s ratepayers”; (2) they should
be paid for by the parent entity (presumably meaning Entergy’s shareholders); and (3) an assets-
based allocator is not appropriate.755


         As to Dr. Szerszen’s assertion that Texas ratepayers do not benefit from the costs captured by
these project codes, ETI witness Domino, President of Entergy, provided anecdotal evidence that
that Entergy was vital to ETI’s restoration efforts on two fronts. First, the parent provided cash to
ETI for its hurricane restoration efforts; second, ETI was not required to pay dividends to the parent
while it was strapped for funds due to hurricane restoration efforts.756 With respect to the argument
that an asset-based allocator is not appropriate, Ms. Tumminello testified that the functions covered
by this project code relate to the oversight of all system operations and the stewardship of corporate
assets and that because ETI is part of a corporate group, the allocated charges associated with these
services are relevant to ETI as part of that group. Furthermore, ETI argues, the asset-based allocator
is appropriate because it reflects the cause of the costs incurred, in that services provided relate to
the stewardship of all the corporation’s assets.757




754
      ETI Ex. 69 (Tumminello Rebuttal) at 10-11.
755
      OPC Ex. 1 (Szerszen Direct) at 56-57.
756
      Tr. at 141.
757
      ETI Ex. 69 (Tumminello Rebuttal) at 9-11.
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          Dr. Szerszen took too narrow a view and, without justification, argued that these costs
provide no benefit to Texas ratepayers. There are innumerable benefits provided by the corporate
structure adopted; those mentioned by Mr. Domino are just a few. Ms. Tumminello’s testimony
explained why an asset-based allocator is appropriate. Accordingly, the ALJs recommend the
Commission approve the inclusion of these costs as requested by ETI.


          3. Project F3PCR73345 (Quick Payment Center, Adm)

          Dr. Szerszen recommended that these costs be reallocated using the CUSTCALL billing
method. Given ESI’s demonstrated tracking capabilities, Dr. Szerszen reallocated the costs of this
project using a 10.8 percent customer call allocator, which is on the low end of the
10.70 percent-11.04 percent Test-Year CUSTCALL allocators.758 As a result of Dr. Szerszen’s
reallocation, $14,484 associated with this project should, according to Dr. Szerszen, be
disallowed.759


          ETI witness Stokes responded, stating that Dr. Szerszen’s proposed reallocation is arbitrary
and fails to consider the cost causation associated with the actual project code at issue. These costs
are not driven by a specific proportion of calls from each Operating Company (that is, by the
CUSTCALL allocator). The costs captured by Project F3PCR73345 reflect the costs of overseeing
the Quick Payment Center vendors in each of the Entergy Operating Companies, regardless of the
number of calls by customers to the Company.760


          The ALJs are persuaded that the allocation methodology chosen by ETI is the superior
method and that the CUSTCALL allocator would not be appropriate given the cost causation
associated with the project. Accordingly, the ALJs recommend the Commission approve the costs
proposed by ETI.




758
      OPC Exhibit No. 27 (ETI’s Ex. SBT-15, Attachment 6) at 2; Tr. at 838-839.
759
      OPC Exhibit No. 1 (Szerszen Direct) at 77 and 118.
760
      ETI Ex. 66 (Stokes Rebuttal) at 11.
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          4. Project F3PCF23936 (Manage Cash)

          Dr. Szerszen recommended disallowance of $15,677 from Project F3PCF23936 (Manage
Cash), arguing that this project: (1) is duplicative of ETI-specific financing and cash management
activates; (2) the allocator is wrong; and (3) Entergy, not ETI ratepayers, should pay for this
activity.761


          ETI witness McNeal testified that the services are not duplicative of the cash management
services performed by the Cash Management department in the Treasury Class. The services
provided under Project F3PCF23936 are associated with daily cash management responsibilities,
such as loading bank balances, setting daily cash position for all the Entergy Companies,
transmitting wire/ACH files to Entergy Company banks for vendor payments, and maintaining
proper cash controls over these cash functions. These services are necessary for the daily operation
of all the Entergy Companies, including ETI, and are thus not directly associated with any one
specific legal entity. The costs are driven by the time spent on the daily cash management activities,
which is directly related to the number of bank accounts that the Entergy Companies have open.
Since the services provided under this project code cannot be identified to a particular Entergy
Company, the billing method based on the number of open bank accounts is the best allocation.
Billing method BNKACCTA does that and, according to Mr. McNeal, is therefore appropriate for
allocating costs for this project code.762


          The evidence demonstrates that the activities captured by this project code are not directly
associated with any one specific entity; rather, they benefit all the entities under the Entergy
umbrella. It also appears that a billing method based on the number of open bank accounts is the
appropriate allocation methodology. Accordingly, the ALJs recommend the Commission approve
inclusion of costs as requested by ETI.




761
      OPC Ex. 1 (Szerszen Direct) at 74 and Schedule CAS-15.
762
      ETI Ex. 61 (McNeal Rebuttal) at 4, 6; Tr. at 546-547.
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PUC DOCKET NO. 39896


I.        Human Resources Class

          Dr. Szerszen recommended disallowances for three project codes that are primarily within
the Human Resources Class of affiliate costs: (1) F3PCHRCCSM (HR Competitive Compensation)
for a disallowance of $20,146; (2) F5PCZUBENQ (Non-Qualified Post-Retirement) for a
disallowance of $115,078; and (3) F5PPZNQBDU (Non-Qual Pension/Benf-Dom Utl) for a
disallowance of $241,073.763


          1. Project F3PCHRCCSM (HR Competitive Compensation)

          Dr. Szerszen testified that an asset-based allocator is not appropriate for a project, such as
Project F3PCHRCCSM, that captures overall executive management-related costs.764


          ETI contends that the functions covered by this project code relate to the oversight of all
system operations and the stewardship of corporate assets and that because ETI is part of a corporate
group, the allocated charges associated with these services are relevant to ETI as part of that group
of companies. Furthermore, ETI argues, the asset-based allocator is appropriate because it reflects
the cause of the costs incurred, in that services provided relate to the stewardship of all the
corporation’s assets.765


          A corporation cannot function without executives, who are charged with the responsibility of
overseeing, among other things, the assets of the corporation. This is an important function that
Dr. Szerszen did not acknowledge in her testimony. The utility and executive management class
costs that she challenged are reasonable and necessary costs that are allocated to ETI based on a
logical allocator – the assets the executives are charged with overseeing. The ALJs recommend that
OPC’s challenge be rejected.




763
      OPC Ex. 1 (Szerszen Direct) at 56, 68.
764
      OPC Ex. 1 (Szerszen Direct) at 56.
765
      ETI Ex. 4 (Domino Direct) at 18-38; ETI Ex. 69 (Tumminello Rebuttal) at 9-11.
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          2. Projects F5PCZUBENQ (Non-Qualified Post-Retirement) and F5PPZNQBDU
             (Non-Qual Pension/Benf-Dom Utl)

          With respect to Projects F5PCZUBENQ and F5PPZNQBDU, Dr. Szerszen testified that:
(1) there is no evidence that Texas ratepayers benefit from the pension-related benefits in these
codes; and (2) the LBRBILAL allocator (Labor Billings to All) is not appropriate because the
benefits are unrelated to ESI labor costs.766


          Initially, ETI agrees that $112,531 of the costs in total for both of these project codes should
be excluded because that amount is attributable to nuclear and non-regulated employees.767


          With respect to the remaining costs, ETI disagrees. The ALJs, however, have already
resolved this issue in their discussions related to Section VII.D.4, above, where they concluded that
that the supplemental executive retirement plans are not reasonable and necessary for the provision
of electric utility service and are not in the public interest. Accordingly, the ALJs recommend the
Commission accept OPC’s proposed disallowance of $356,151 (which includes the $112,531 agreed
to by ETI).


J.        Information Technology Class

          Dr. Szerszen recommended disallowances in two project codes that are primarily within
ETI’s Information Technology Class: (1) F3PPFXERSP (Evaluated Receipts Settlement) for a
disallowance of $10,279; and (2) F3PCFX3555 (BOD/Executive Support) for a disallowance of
$3,148.768




766
      OPC Ex. 1 (Szerszen Direct) at 68.
767
      ETI Initial Brief at 179.
768
      OPC Ex. 1 (Szerszen Direct) at 56, 71.
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          1. F3PPFXERSP (Evaluated Receipts Settlement)

          Dr. Szerszen testified that Project F3PPFXERSP is not moving forward due to tax and freight
implications and, as such, the cost is not recurring.769 Ms. Tumminello testified in response that the
“Evaluated Receipt Settlement” program was originally being capitalized in a capital project. But
when it was decided that the program would be cancelled, the capital project was closed and the
charges to the project were expensed. Although the costs for this particular project do not recur
every year, they are part of normal utility operations, and this type of project does recur as
necessary.770


          Although the ALJs understand the concept of normally recurring cost types, they do not
believe that the costs captured by this project code fall within that category. Those costs related to a
project that was cancelled and sufficient explanation of how similar projects in the future might
occur was not provided. Accordingly, the ALJs recommend the Commission reject inclusion, as
proposed by OPC.


          2. Project F3PCFX3555 (BOD/Executive Support)

          Dr. Szerszen argued that Project F3PCFX3555 is an executive-related project that does not
provide perceivable benefits to ETI ratepayers, the Entergy shareholders should bear this cost, and
an assets-based allocator is not appropriate.771


          ETI argues that the functions covered by this project code relate to the oversight of all system
operations and the stewardship of corporate assets and that because ETI is part of a corporate group,
the allocated charges associated with these services are relevant to ETI as part of that group of
companies. Furthermore, ETI argues, the asset-based allocator is appropriate because it reflects the




769
      OPC Ex. 1 (Szerszen Direct) at 71.
770
      ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4.
771
      OPC Ex. 1 (Szerszen Direct) at 56.
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cause of the costs incurred, in that services provided relate to the stewardship of all the corporation’s
assets.772


          A corporation cannot function without executives who are charged with the responsibility of
overseeing, among other things, the assets of the corporation. This is an important function that
Dr. Szerszen did not acknowledge in her arguments. The utility and executive management class
costs that she challenged are reasonable and necessary costs that are allocated to ETI based on a
logical allocator – the assets the executives are charged with overseeing. The ALJs recommend that
OPC’s challenge be rejected.


K.        Internal and External Communications Class

          Dr. Szerszen recommended disallowances in four project codes that are primarily within
ETI’s Internal and External Communications Class: (1) F3PCR40118 (Utility Communications for a
$6 disallowance; (2) F5PCZPDEPT (Supervision and Support – Public) for a $138 disallowance;
(3) F5PPICC000 (Integrated Customer Communications) for a $199 disallowance; and
(4) F5PPICCEMP (ICC - Employee Education Initiative) for a $3 disallowance.773


          ETI witness Tumminello responded to Dr. Szerszen’s claim that the costs captured by these
project codes are corporate image costs by stating that the costs are for advertising activities that are
of a good will or institutional nature, which is primarily designed to improve the image of the utility
or the industry, including advertisement which inform the public concerning matters affecting the
Company’s operations, such as, the costs of providing service, the Company’s efforts to improve the
quality of service, the Company’s efforts to improve and protect the environment. According to
FERC, such costs are properly includable in FERC Account 930.1 and are recoverable. According
to Ms. Tumminello, as contemplated by FERC, the fact that ETI is a monopoly has no bearing on the
recoverability of these costs.774


772
      ETI Ex. 4 (Domino Direct) at 18-38; ETI Ex. 69 (Tumminello Rebuttal) at 9-11.
773
      OPC Ex. 1 (Szerszen Direct) at 66.
774
      ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4-6.
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PUC DOCKET NO. 39896


        OPC provided little support for its claim that costs covered by these project codes should not
be recoverable, essentially limiting the basis to the contention that ETI is a monopoly and ratepayers
should not be charged with such costs. ETI did little better, but it did provide the testimony of
Ms. Tumminello, which confirms that the costs are properly includable in FERC Account 930.1 and
are, therefore, recoverable. In the end, the ALJs must go with the weight of the evidence, which is
in ETI’s favor. The ALJs recommend the Commission reject OPC’s contention that costs covered
by these project codes are not recoverable.


L.      Legal Services Class

        Dr. Szerszen recommended disallowances in 13 project codes that are primarily within the
Legal Services Class: (1) F3PPCASHCT (Contractual Alternative/Cashpo) for a disallowance of
$2,553; (2) F3PCF99180 (CORP. COMPLIANCE TRACKING SYS) for a disallowance of $9;
(3) F3PPINVDOJ (DOJ Anti Trust Investigation) for a disallowance of $1,039,664;775
(4) F3PCE01601 (Ferc - Open Access Transmission) for a disallowance of $84,183;
(5) F3PCERAKTL (RAKTL Patent Matter) for a disallowance of $75; (6) F3PPEASTIN
(Willard Eastin et al) for a disallowance of $19,714; (7) F3PPTCGS11 (TX Docket Competitive
Generation) for a disallowance of $310,746; (8) F5PCE13759 (Jenkins Class Action Suit) for a
disallowance of $205,107; (9) F5PCZLDEPT (Supervision & Support – Legal) for a disallowance of
$225,794; (10) F3PCCDVDAT (Corporate Development Data Room) for a disallowance of $6,147;
(11) F3PCSYSAGR (System Agreement-2001) for a disallowance of $880,841; (12) F3PPWET302
(SPO 2008 Winter Western Region) for a disallowance of $13,919; and (13) F3PPWET308 (SPO
Calpine PPA/Project Houston) for a disallowance of $435,963.




775
    Dr. Szerszen also proposed disallowance of $765 in charges for related Project Code F3PPTDHY19
(Dept. of Justice Investigation), which is actually primarily attributable to the Transmission Operations Class,
rather than the Legal Services Class. Because the issues are intertwined, that project will be discussed here,
rather than in the Transmission Operations Class.
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          1. Project F3PPCASHCT (Contractual Alternative/Cashpo)

          With respect to Project F3PPCASHCT ($2,553 disallowance), ETI agrees that these costs are
non-recurring and should be disallowed. Accordingly, the ALJs recommend the Commission
exclude those costs.


          2. Project F5PCZLDEPT (Supervision & Support – Legal)

          As to Project F5PCZLDEPT ($225,794), OPC, through its Second Errata, removed that
proposed disallowance, and it is no longer contested by Dr. Szerszen. Accordingly, the ALJs
recommend the Commission approve inclusion of those costs.


          3. Project F3PCF99180 (Corp. Compliance Tracking Sys)

          F3PCF99180 (Corp. Compliance Tracking Sys) is one of the project codes that Dr. Szerszen
claimed should be disallowed because ETI is a monopoly and Texas ratepayers should not have to
pay for corporate image costs.776


          ETI witness Tumminello testified that these costs are for advertising activities that are of a
good will or institutional nature, which is primarily designed to improve the image of the utility or
the industry, including advertisement which inform the public concerning matters affecting the
Company’s operations, such as, the costs of providing service, the Company’s efforts to improve the
quality of service, the Company’s efforts to improve and protect the environment. According to
FERC, such costs are properly includable in FERC Account 930.1 and are recoverable. According
to Ms. Tumminello, as contemplated by FERC, the fact that ETI is a monopoly has no bearing on the
recoverability of these costs.777


          OPC provided little support for its claim that costs covered by these project codes should not
be recoverable, essentially limiting the basis to the contention that ETI is a monopoly and ratepayers
should not be charged with such costs. ETI did little better, but it did provide the testimony of

776
      OPC Ex. 1 (Szerszen Direct) at 66.
777
      ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4-6.
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PUC DOCKET NO. 39896


Ms. Tumminello, which confirms that the costs are properly includable in FERC Account 930.1 and
are, therefore, recoverable. The weight of the evidence is in ETI’s favor. The ALJs recommend the
Commission reject OPC’s contention that costs covered by these project codes are not recoverable.


           4. Projects F3PPINVDOJ (DOJ Anti Trust Investigation) and F3PPTDHY19 (Dept. of
              Justice Investigation)

           Entergy is currently under investigation by the Department of Justice (DOJ) for certain
business practices of the Operating Companies, including the procurement of generating assets and
power, dispatch of generation within the Entergy system, and transmission capacity expansion. This
is a civil investigation under Section 2 of the Sherman Act and Section 7 of the Clayton Act. The
investigation has been ongoing since 2010, and Entergy does not know when the investigation will
conclude.778


           Dr. Szerszen testified that there are two reasons why ratepayers should not pay for the DOJ
expenses. First, ETI does not have the ability to make its own power procurement, generation
dispatch, or transmission capacity decisions. These decisions are made by ESI and Entergy’s
corporate management, which has traditionally planned and managed the electric operating
companies’ generation and transmission functions on a system-wide basis. Second, ETI is not
responsible for the development and administration of the system agreement, and should not be held
responsible for these antitrust investigation expenses. Furthermore, according to Dr. Szerszen, if the
DOJ finds that Entergy has acted illegally, it is even more inappropriate to charge ETI ratepayers for
corporate-level illegal actions. These expenses should be borne by Entergy’s corporate parent
and/or the corporation’s shareholders, and not the ratepayers.779


           ETI contends that Dr. Szerszen fundamentally misunderstands the nature of the System
Agreement and the benefits that ETI derives from that agreement. All of the Entergy Operating
Companies voluntarily entered into the System Agreement so that the Entergy system can be
planned and operated on a total system basis, in order to maximize economic benefit and reliability

778
      OPC Ex. 1 (Szerszen Direct) at 51-52.
779
      Id. at 52.
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of service. All of the Operating Companies benefit from integrated planning and operations in this
manner. This does not mean that ETI has no decision-making role in these activities. ETI notes that
under Section 5.01 of the System Agreement, the agreement is administered through an Operating
Committee, which includes an ETI representative, as well as representatives of the other Operating
Companies and Entergy. ETI’s representative is one of the voting members of the Committee, and
all decisions of the Operating Committee must be approved by a majority vote. As a voting member
of the Operating Committee, ETI is responsible for administering the System Agreement and does
participate in decision-making on generation and transmission matters.780


            ETI acknowledges that ESI is tasked with providing services and making decisions related to
generation dispatch, power procurement, and transmission operations on behalf of the Entergy
Operating Companies and at the direction of the Operating Committee, but these activities are for
the benefit of the Operating Companies and their ratepayers. ETI receives the benefits of these
services and integrated planning and operations under the System Agreement and, according to ETI,
should also be responsible for its portion of costs related to those services and operations.781


            As to Dr. Szerszen’s contention that the costs should be disallowed because DOJ might find
that Entergy acted illegally, ETI notes that the DOJ is not an adjudicatory body or regulatory agency
and, thus, it does not make “findings of fact.” If DOJ believes the civil antitrust laws have been
violated, it can file a complaint in federal district court. To date, no complaint has been filed. ETI
points out that ESI routinely incurs legal costs in responding to regulatory audits and investigations
on behalf of ETI and the other Operating Companies in the same manner in which other operating
costs are incurred. ESI is authorized to retain legal counsel on behalf of, and for the benefit of, ETI
and the other Entergy Operating Companies. ESI is authorized to allocate the respective costs to the
Operating Companies under a service agreement with the Entergy Operating Companies designated
as Rate Schedule FERC No. 435. This service agreement is on file with, and was approved by,




780
      ETI Ex. 65 (Sloan Rebuttal) at 8.
781
      Id.
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FERC under FERC Docket No. ER07-38-000.782 Thus, according to ETI, it is appropriate that ETI
is allocated its share of the costs of legal services related to the DOJ investigation.783


          The DOJ antitrust investigation is a massive undertaking. Unfortunately, it is a part of the
ordinary course of modern business life. OPC’s arguments that ESI is solely responsible for
decision-making under the System Agreement miss the mark, as pointed out by ETI. It is clear that
ETI and the other Operating Companies play an active role in the decision-making. As to OPC’s
arguments about what would happen if Entergy were found to have violated the antitrust laws, those
arguments are little more than speculation. As ETI noted, the DOJ is not an adjudicatory body and
its investigation can only result in the filing of a complaint in Federal court (if the DOJ believes that
such an action is justified). Until that time, it is imperative for the company to fully respond to the
DOJ investigation. The ALJs find that ETI has met its burden of proving that Texas ratepayers
should be charged the costs of the DOJ investigation allocated to them by ETI.


          5. Project F3PCE01601 (Ferc - Open Access Transmission)

          Project F3PCEO1601 costs are incurred to manage costs associated with regulatory oversight
and coordination of the Entergy System Open Access Transmission Service before FERC. OPC
contends that not only are most of the FERC dockets accruing costs under Project F3PPEO1601 no
longer open as of December 31, 2011,784 most of the closed dockets have absolutely nothing to do
with Texas operations.785 Furthermore, according to OPC, ETI witness Sloan agreed that only three
of the dockets shown in OPC Exhibit No. 12 were open at the end of the test year, and one of the
open dockets involves a transmission service agreement involving the Missouri Joint Municipal
Electric Utility Commission and various cities in Missouri and Arkansas.786




782
      Entergy Serv. Inc., 117 FERC ¶ 61,288 (2006).
783
      ETI Ex. 65 (Sloan Rebuttal) at 8-9.
784
      OPC Ex. 12 (OPC RFI No. 7-3); OPC Ex. 3 (Szerszen Workpapers) at 363.
785
      OPC Ex. 12 (OPC RFI No. 7-3); OPC Ex. 1 (Szerszen Direct) at 54.
786
      Tr. at 280.
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          ETI responds that the activities in this project relate to oversight and coordination of the
OATT proceedings before the FERC. Costs billed to this project code are related to ESI’s
representation of the Operating Companies, including ETI, before the FERC on OATT issues.
Revenues derived from provision of service under the OATT are credited to all of the Operating
Companies on a load responsibility ratio basis. ETI’s retail share of these revenues was $168,366
during the test period, demonstrating the benefits derived by Texas ratepayers as a result of the
activities undertaken through this project code.787


          Activities relating to a company’s OATT are not one-time activities; they will continue from
year to year. OPC’s contention that because most of the dockets listed as having taken place during
the Test Year were completed by the end of the Test Year they should be disregarded is not
well-founded. It is clear that the activities covered by this project code not only benefit ETI’s Texas
ratepayers, but will continue (albeit under new docket numbers) into future years. The ALJs
recommend that costs under this project code be allowed.


          6. Project F3PCERAKTL (RAKTL Patent Matter)

          The costs under this project code involve the RAKTL patent, which relates to call center
operations. RAKTL is a patent infringement claim lodged against several Entergy companies. The
alleged patents are for voice prompting technology used in call centers.788


          Dr. Szerszen testified that it is not appropriate to charge ETI for the costs associated with this
litigation because ETI did not purchase the call center telephone equipment at issue, and therefore
should not be required to pay any legal costs associated with patent infringement investigation or
settlement costs. ESI is totally responsible for system-wide technology purchases and operations,
and, according to Dr. Szerszen, it is not reasonable to require the operating companies to pay legal
costs associated with ESI technology acquisition or technology application errors.789


787
      ETI Ex. 65 (Sloan Rebuttal) at 10.
788
      Id. at 4; OPC Ex. 1 (Szerszen Direct) at 49-50.
789
      OPC Ex. 1 (Szerszen Direct) at 50.
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          ETI contends that ESI incurred the legal expenses on this patent matter on behalf of the
Entergy Operating Companies, whose residential and small commercial customers call into the call
centers to obtain customer service for issues related to connection and disconnection of electric
service, billing issues, and other customer transactions. The call centers provide an interface
between ETI customers and the Entergy Operating Companies and, as such, are valuable in
providing quality service to customers. Consequently, according to ETI, costs related to the call
centers, including the costs of defending lawsuits involving technologies used at those call centers, is
a reasonable and necessary expense that is appropriately allocated to ETI.790


          OPC tends to ignore the purpose and benefits of a centralized service company such as ESI.
If ETI were to fund stand-alone call centers, it is likely that the costs to Texas ratepayers would be
higher than those proposed by ETI in this case. Part of the costs that ESI incurs is the cost of patent
claims. Those are legitimate costs that should be borne by all who receive service from ESI.
Accordingly, the ALJs recommend the Commission reject OPC’s challenge.


          7. Project F3PPEASTIN (Willard Eastin et al.)

          This project code, which contains costs in the amount of $19,714, collects costs related to an
age discrimination law suit filed by Willard Eastin, et al. against Entergy. The defendants to the
lawsuit were Entergy, ESI, Entergy Louisiana, Inc. (ELL), and Entergy New Orleans, Inc. (ENOI).
The plaintiffs to the lawsuit were employees of ESI, ELL, and ENOI.791


          OPC witness Szerszen testified that ETI should not be required to pay any of the costs of this
litigation. Although ESI provides services to the Operating Companies, this does not imply that the
Operating Companies should be charged costs associated with the service company’s employment
practice problems or errors according to Dr. Szerszen.792




790
      ETI Ex. 65 (Sloan Rebuttal) at 4.
791
      ETI Ex. 65 (Sloan Rebuttal) at 2; OPC Ex. 1 (Szerszen Direct) at 49-50.
792
      OPC Ex. 1 (Szerszen Direct) at 50.
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          ETI argues that costs are driven by ESI having the need for legal services to defend itself. As
shown on the Project Code Summary for this project, since all ESI functions are in service to the
various affiliates and arise as a consequence of providing such services, it is appropriate to relate
these legal costs to the total ESI billings to the affiliates.793


          ETI has provided little in the way of explanation regarding these costs or the litigation that
generated them. What is troubling to the ALJs is that the only named defendants are Entergy, ESI,
ELL, and ENOI; ETI is not included among the named defendants. If this were simply a cost of
doing business for ESI, as claimed by ETI, why were ELL and ENOI named? No explanation was
offered. It appears to the ALJs that although this litigation is related to ESI’s operations, it is more
immediately related to ELL and ENOI. The ALJs do not believe that ETI’s Texas ratepayers should
be charged for these costs; therefore the ALJs recommend that $19,714 not be included.


          8. Project F3PPTCGS11 (TX Docket Competitive Generation)

          The costs billed through this project code all pertain to ETI’s CGS matter currently pending
before the Commission in Docket No. 38951.794


          OPC witness Szerszen testified that because no decision has been made yet as to the
disposition of the expenses associated with the CGS tariff, ETI should not be expensing the costs
associated with that docket. Dr. Szerszen disallowed $310,746 in Test-Year expenses, and
recommended that ETI be allowed to defer the expenses until the Commission determines the
appropriate regulatory treatment.795


          ETI argues that these costs were incurred during the Test Year in a pending Commission
docket, and ETI continues to incur costs related to this matter. As such, according to ETI, these




793
      ETI Ex. 65 (Sloan Rebuttal) at 2.
794
      Id. at 5; OPC Ex. 1 (Szerszen Direct) at 50.
795
      OPC Ex. 1 (Szerszen Direct) at 50.
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costs are appropriately included in ETI’s cost of service and should neither be disallowed nor
deferred.796


          OPC’s arguments with respect to these costs are not well-founded. It appears to be likening
these regulatory costs to rate case expense, which would be subject to Commission review and
approval in the proceeding to which they relate. But that is not the nature of these expenses. They
are simply regulatory expenses incurred in the course of ongoing regulatory proceedings. They are
ordinary and necessary expenses, the reasonableness of which OPC did not challenge. Accordingly,
the ALJs find that it is appropriate for ETI to charge these expenses to its Texas ratepayers.


          9. Project F5PCE13759 (Jenkins Class Action Suit)

          The project code relates to a class action lawsuit filed in Texas District Court in 2003 on
behalf of all Texas retail customers served by ETI’s predecessor-in-interest, EGSI (Jenkins Class
Action).      The Jenkins Class Action plaintiffs allege that they have been damaged due to
manipulation of the dispatch and pricing of the Entergy system’s generating units and electricity
purchases. As a result of this alleged manipulation, they contend that ETI’s Texas retail customers
were charged more than they should have been for purchased power.797 Dr. Szerszen asserted there
are three reasons why these legal expenses should not be borne by ETI:


x     ESI charges 100 percent of the legal expenses to ETI, even though ETI is only          one of
      several defendants;

x     ETI claims that it is defending practices relating to system operations, but fails           to
      acknowledge that Entergy’s system operations are comprised of many generation               and
      transmission components other than those of ETI; and

x     ETI does not have any authority to administer the System Agreement, that        being a function
      solely within the purview of ESI.798



796
      ETI Ex. 65 (Sloan Rebuttal) at 5.
797
      OPC Ex. 1 (Szerszen Direct) at 49; ETI Ex. 65 (Sloan Rebuttal) at 2-3.
798
      OPC Ex. 1 (Szerszen Direct) at 49.
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Dr. Szerszen testified that “[i]t would be more appropriate for the Entergy parent to be charged for
these lawsuit expenses, particularly since ETI cannot make unilateral power purchases and power
sales decisions.”799


            ETI responds that the plaintiffs in this lawsuit are challenging the reasonableness of ETI’s
Commission-set rates and that the Commission has filed an amicus brief in support of ETI’s position
in the case. ETI further argues that retail ratepayers are benefitting from ETI’s pursuit of the
litigation because ETI is defending practices that are in place to ensure the lowest reasonable cost
consistent with system reliability. Finally, ETI states that the costs are reasonable and necessary
expenses because the plaintiffs purport to represent only ETI’s ratepayers and seek to recover
damages inconsistent with ETI’s filed rates approved by the Commission.800


            The ALJs understand Dr. Szerszen’s concerns that there are multiple defendants involved in
this litigation, there are many aspects to Entergy’s system operations, and ETI does not have power
to unilaterally make decisions under the System Agreement. The crucial point, however, is that
these are Texas ratepayers pursuing a challenge to ETI’s Texas rates. The matter centers around
Texas, and the costs of the litigation should be borne by Texas ratepayers.


            10. Project F3PCSYSAGR (System Agreement-2001)

            OPC witness Szerszen disallowed $880,841 in legal expenses regarding the 2001 complaint
filed by the Louisiana Public Service Commission and the City of New Orleans seeking revisions to
the Entergy System Agreement.801 OPC states that it generally agrees with ETI witness Sloan that
the complaint challenges the equalization of costs between all Entergy Operating Company
jurisdictions.802      However, OPC does not agree that the inquiry “will” affect all Entergy
jurisdictions. Texas has benefitted from the complaint primarily through the past receipt of
equalization payments pursuant to FERC’s decision in this complaint matter. However, Entergy’s

799
      Id.
800
      ETI Ex. 65 (Sloan Rebuttal) at 3.
801
      OPC Ex. 1 (Szerszen Direct) at 53.
802
      ETI Ex. 65 (Sloan Rebuttal) at 9.
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SEC Form10-K shows that for 2012 and 2013, ETI will receive no equalization payments, and
further shows that ETI received no rough production cost equalization payments in 2010.803 Thus,
according to OPC, the legal expenses sought to be recovered under Project F3PCSYSAGR are non-
recurring for ETI and therefore not representative of future costs and should be removed from ETI’s
cost of service.804


          ETI established that this litigation involved the System Agreement, which governs the
equalization of costs between all of the Entergy Operating Company jurisdictions, it provides
benefits to ETI’s Texas ratepayers as well as those of the other Entergy Operating Companies.
OPC’s argument that ETI did not receive equalization payments in 2010 and is non-recurring for
ETI does not overcome the benefits received by ETI’s Texas ratepayers. The ALJs recommend that
OPC’s disallowance be denied.


          11. Project F3PCCDVDAT (Corporate Development Data Room)

          ETI requests the recovery of $6,147 in ESI allocated costs for the corporate development
data room. The stated purpose of the data room is for due diligence reviews associated with Entergy
merger, acquisition, or diversification activities. The expenses associated with the corporate
development data room are for the gathering, collating, indexing, manning, and storage of data
during the due diligence reviews.805 OPC contends that the costs incurred for the corporation’s
analysis of merger, acquisition, and diversification opportunities should not be charged to ETI’s
ratepayers. Entergy has not acquired any utilities or utility operations that might produce
system-wide benefits to utility customers.806 The $6,147 of expenses for the corporate development
room are not reasonable and necessary expenses that ratepayers should shoulder and therefore,
according to OPC, recovery of these expenses should be disallowed.




803
      ETI Ex. 98 (Entergy’s SEC Form 10-K) at 79-80.
804
      OPC Ex. 1 (Szerszen Direct) at 52-53.
805
      OPC Ex. 3 (Szerszen Workpapers) at 394.
806
      OPC Ex. 1 (Szerszen Direct) at 45-46.
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PUC DOCKET NO. 39896


          ETI responds that these costs are driven by each company’s need for corporate services and
the costs, therefore, are appropriately allocated based on the level of service provided by ESI, which
is a reasonable proxy of each company’s need for corporate services.807 Further, just because
Entergy has not acquired any utility or utility operations in the recent past does not mean that these
are not reasonable and necessary costs. Entergy points out that as Dr. Szerszen noted in her
description of this project, it is not only for the acquisition of other operating units, but also used to
analyze diversification activities, which is a legitimate and reasonable undertaking by an integrated
utility and its parent company.


          The ALJs believe that there are legitimate costs that may not on their face appear to be
properly allocable to entities such as ETI, but on closer examination they merit such an allocation.
These fall into that class. As Ms. Tumminello testified, the Corporate Development Data Room
includes costs not only related to mergers and acquisitions, but also diversification activities that
could benefit ETI ratepayers. Accordingly, they are properly allocated to ETI ratepayers.


          12. Project F3PPWET302 (SPO 2008 Winter Western Region)

          Dr. Szerszen argued that Project F3PPWET302 costs should be disregarded because they
were incurred during the 2008-2009 period, which is outside of the Test Year, and they are
nonrecurring.808

          ETI witness Cicio explained that although this project was initiated prior to the Test Year,
the costs that the Company seeks to recover through this project code were expenses incurred during
the Test Year. These costs included development activities, requests for proposal issuance, bidders’
conferences, written and posted questions and answers from market participants and other interested
parties, submission of proposals, screening of proposals, proposal evaluation, follow-up questions
and clarifications, recommendations and awards, contract negotiations, Independent Monitor reports,
and regulatory approvals, if necessary. He stated that these types of costs routinely encompass a
multi-year time frame, and the costs required to perform those activities, although associated with a

807
      ETI Ex. 69 (Tumminello Rebuttal) Ex. SBT-R-2 at 1.
808
      OPC Ex. 1 (Szerzen Direct) at 65.
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PUC DOCKET NO. 39896


project that may have been initiated several years previously, are properly incurred over the life span
of the project. He also stated that they are recurring because they reflect the kinds and levels of
charges that would be expected to be incurred on an ongoing basis in association with request for
proposals managed by ESI on behalf of the Entergy Operating Companies, and the Company has
been involved in these types of solicitations since 2002.809


          The ALJs find that the costs captured by Project F3PPWET302 were incurred during the Test
Year and represent the kinds and levels of costs routinely incurred on a recurring basis.
Accordingly, the ALJs recommend the Commission approve their inclusion as requested by ETI.


          13. Project F3PPWET308 (SPO Calpine PPA/Project Houston)

          With respect to Project F3PPWET308, which deals with the Calpine-Carville purchased
power agreement, Dr. Szerszen testified that the costs were either non-recurring, or rate case
expenses, or expenses that should have been charged to Louisiana ratepayers.810


          ETI witness Cicio explained that these are recurring costs because they reflect the kinds and
levels of charges that the Company expects to incur on an ongoing basis in association with RFPs
managed by ESI on behalf of the Entergy Operating Companies; they were not incurred as part of
some rate case preparation and, therefore, are not a rate case expense that is otherwise sought for
recovery by ETI; and the costs in the matter are costs that were billed only to Texas and should not
have been billed to Louisiana because there is a separate project code that captures the Louisiana
costs that are billed to Louisiana.811


          The ALJs find that these costs, like those captured by Project F3PPWET302, are recurring in
that they represent the kinds and levels of costs routinely incurred on a year-in and year-out basis.
Further, the ALJs find that the costs should not have been charged to Louisiana and that there



809
      ETI Ex. 45 (Cicio Rebuttal) at 13-14.
810
      OPC Ex. 1 (Szerszen Direct) at 65-66.
811
      ETI Ex. 45 (Cicio Rebuttal) at 14-17.
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PUC DOCKET NO. 39896


existed a separate project code to capture costs attributable to Louisiana. Accordingly, the ALJs
recommend the Commission approve the inclusion of these costs as requested by ETI.


M.        Other Expenses Class

          Dr. Szerszen recommended disallowances in 11 project codes that are primarily within the
Other Expenses Class of affiliate costs: (1) F3PCSPETEI (Entergy-Tulane Energy Institute) for a
disallowance of $14,288; (2) F3PCC08500 (Executive VP, Operations) for a disallowance of $4,117;
(3) F3PPBFMESI (ESI Function Migration Relocation) for a disallowance of $4,187;
(4) F3PPBFRESI (ESI Business Function Relocation) for a disallowance of $11,444;
(5) F3PPDRPESI (ESI Disaster Recovery Plan Charge) for a disallowance of $761;
(6) F5PPBFMREL (Business Function Migration Employee) for a disallowance of $33,624;
(7) F5PPBFRREL (Business Function Relocation) for a disallowance of $15,624; (8) F5PPBFRSEV
(Business Function Relocation Severance) for a disallowance of $3,066; (9) F5PPDRPREL (Disaster
Recovery Plan Relocation) for a disallowance of $31,006; (10) F5PPETXRFI (2009 Texas Ike
Recovery Filing) for a disallowance of $441; and (11) F5PPKATRPT (Storm Cost Processing &
Review) for a disallowance of $929.812


          1. Projects F3PCSPETEI (Entergy-Tulane Energy Institute) and F5PPKATRPT
             (Storm Cost Processing & Review)

          ETI agrees with Dr. Szerszen that the $14,288 amount she proposed to disallow for Project
F3PCSPETEI (Entergy-Tulane Energy Institute) can be treated as a donation, and so should be
removed from ETI’s cost of service. ETI also agrees with Dr. Szerszen to remove the $929 billed to
ETI under Project F5PPKATRPT (Storm Cost Processing & Review). The charges for the
remaining nine project codes, however, are contested.




812
      OPC Ex. 1 (Szerszen Direct) at 56, 67, and 72.
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          2. Project F3PCC08500 (Executive VP, Operations)

          As to Project F3PCC08500 (Executive VP Operations), Dr. Szerszen testified that an
asset-based allocator is not appropriate for these types of executive management costs, and there is
“no perceivable benefit” to ETI ratepayers for these types of allocated costs.813


          Ms. Tumminello disagreed, stating that asset-based allocation methods are selected for
projects where the costs are driven by the oversight and stewardship of corporate assets of the
Entergy Companies including, but not limited to, services provided by financial management and
certain finance functions, among others.          Each Entergy affiliate with assets on Entergy’s
consolidated balance sheet will be billed their proportionate share of the costs. The use of the Total
Assets allocation method is, in fact, an appropriate method to allocate corporate-level corporate
governance type services.814


          The ALJs find credible ETI’s assertion that the costs captured by this project code are for
oversight and stewardship of the corporate assets of Entergy and, therefore, an asset-based allocator
is appropriate. Accordingly, the ALJs recommend the Commission reject OPC’s challenge to the
inclusion of these costs.


          3. Projects F3PPBFMESI (ESI Function Migration Relocation), F3PPBFRESI (ESI
             Business Function Relocation), F3PPDRPESI (ESI Disaster Recovery Plan Charge),
             F5PPBFMREL (Business Function Migration Employee), F5PPBFRREL (Business
             Function Relocation), F5PPBFRSEV (Business Function Relocation Severance),
             F5PPDRPREL (Disaster Recovery Plan Relocation), and F5PPETXRFI (2009
             Texas Ike Recovery Filing)

          The remaining eight of the project codes attributable to the Other Expenses Class all deal
with system restoration and business continuity resulting from Hurricane Katrina, with one applying
to Hurricane Ike. Dr. Szerszen testified that these costs should be disallowed because they should
not be considered to be system restoration costs or, if they are, citing to PURA § 36.405, ETI should
have requested recovery of these costs in its first base rate following Hurricane Katrina (Docket

813
      Id. at 56-57.
814
      ETI Ex. 69 (Tumminello Rebuttal) at 9-10.
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No. 34800). She also testified that ETI has not shown that Texas ratepayers benefited from these
costs.815


          Ms. Tumminello testified that because of the magnitude of Hurricane Katrina, these expenses
were necessary so that activities in connection with the restoration of service and infrastructure
associated with electric power outages affecting customers could continue. These expenses relate to
critical functions needed to support storm restoration, such as business function relocation, and
provided a direct benefit to ratepayers. Ms. Tumminello stated that the costs in seven of these
project codes (F3PPBFMESI, F3PPBFRESI, F3PPDRPESI, F5PPBFMREL, F5PPBFRREL,
F5PPBFRSEV, and F5PPDRPREL) are being amortized over five years. Though these particular
costs do not recur every year, they are a part of ETI’s normal utility operations given the service area
served by ETI, and do recur as necessary.816


          As to Dr. Szerszen’s legal conclusion that ETI is no longer authorized to recover Hurricane
Katrina costs, ETI argues that PURA § 36.405 does not restrict or even apply to ETI’s recovery of
such costs. That section deals with securitization of system restoration costs, but ETI did not seek to
securitize any Hurricane Katrina costs. Even so, argues ETI, if that section did apply, it does not
restrict system restoration cost recovery solely to Docket No. 34800; that is, the “next base rate
proceeding” following the hurricane. Instead, the final clause in PURA § 36.405(a) states in full that
the Company is entitled to recover such costs “in its next base rate proceeding or through any other
proceeding authorized by Subchapter C or D.” The same point applies to the Hurricane Ike costs;
while ETI did securitize the Hurricane Ike costs that it had incurred up to the date subject to that
securitization, it continued to incur costs in this test year for that storm restoration (in this case, $441
billed to the Ike-related project code). The costs in these projects were incurred during the test year
for this docket and could not have been recovered in an earlier docket. Moreover, ETI’s filing in




815
      OPC Ex. 1 (Szertrszen Direct) at 72, Schedule CAS-14.
816
      ETI Ex. 69 (Tumminello Rebuttal) at16.
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PUC DOCKET NO. 39896


this docket was filed in accordance with PURA Subchapter C as a rate change proposed by a utility.
As such, ETI contends that it is entitled to recover these costs.817


          To the ALJs, the most important part of the argument is that ETI did not seek to avail itself
of PURA § 36.405 with respect to Hurricane Katrina costs. It is difficult to understand how that
section, which deals with securitization of hurricane costs, could block recovery when ETI did not
seek to securitize those costs. Similarly, with respect to Hurricane Ike costs, the $441 challenged by
Dr. Szerszen was not incurred until the Test Year and could not have been securitized.
Ms. Tumminello provided testimony that the costs were reasonable and necessary, representing a
part of ETI’s normal utility operations. Accordingly, the ALJs recommend the Commission approve
inclusion of the costs.


N.        Regulatory Services Class

          Dr. Szerszen challenged one project code that is primarily within the Regulatory Services
Class of affiliate costs: Project F3PPE9981S (Integrated Energy Management for ESI) for a
disallowance of $171,032.


          Dr. Szerszen testified that these costs were incurred for the implementation, coordination,
and promotion of demand side and supply side management and energy efficiency programs. But,
she stated, these costs should instead have been recovered through ETI’s Energy Efficiency Cost
Recovery Factor (EECRF) Rider and, as such, it is inappropriate to recover these costs through
affiliate billings in base rates.818


          ETI witness May testified that recovery of these costs through base rates rather than through
the EECRF Rider is appropriate because these activities are not subject to an active ETI energy
efficiency program. These activities are more in the nature of general research and development
activities that help drive the Company’s strategy on these topics, such as the timing of implementing
related programs. In the meantime, until these activities result in an actual program proposal, these

817
      ETI Initial Brief at 188-189.
818
      OPC Ex. 1 (Szerszen Direct) at 69-70.
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are legitimate known and measurable costs that the Company has incurred and should then be
recovered from retail customers.819 At the hearing, Mr. May further explained that the costs in this
project code are labor costs that are “not really consistent” with the energy efficiency rule, but
instead involve “primarily costs of investigating” potential future activities (such as smart meters
and electric vehicle chargers) that are generally not consistent with the energy efficiency rider.820
ETI witness Considine also addresses this issue from a regulatory accounting perspective. He
testified: “Because these are not costs that must be, or are currently being recovered through the
EECRF, they are not double recovered and should be included in the Company’s cost of service.”821
According to ETI, the costs in this project code, therefore, are not costs that should or can be
recovered through ETI’s EECRF Rider.


          This is a close call. The Commission’s Energy Efficiency Rule places limits on the amount
of research and development costs a utility may recover,822 which supports the argument that the
costs should be included in the EECRF. Further, it appears to the ALJs that research and
development costs, by their very nature, do not relate to an active program, which negates many of
the arguments advanced by ETI witnesses May and Considine. In the end, the ALJs believe that
these costs should be included in the EECRF. Accordingly, the ALJs recommend the Commission
disallow costs in the amount of $171,032 relating to Project F3PPE9981S.


O.        Retail Operations Class

          Dr. Szerszen challenged three project codes that are primarily within ETI’s Retail Operations
Class of affiliate costs: (1) F5PPICCIMG (ICC – “Image” Message) for a disallowance of $3,912;
(2) F3PPR56640 (Wholesale - EGS-TX) for a disallowance of $229,938; and (3) F3PPR56920
(Wholesale - All Jurisdictions) for a disallowance of $333.




819
      ETI Ex. 57 (May Rebuttal) at 30-31.
820
      Tr. at 1929-1930 and 1934-1935.
821
      ETI Ex. 46 (Considine Rebuttal) at 36.
822
      P.U.C. SUBST. R. 25.181(i).
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          1. Project F5PPICCIMG (ICC – “Image” Message)

          Project Code F5PPICCIMG (ICC-“Image” Message) is one of the project codes that
Dr. Szerszen testified should be disallowed because ETI is a monopoly and Texas ratepayers should
not have to pay for corporate image costs.823


          Ms. Tumminello testified that the costs are for advertising activities that are of a good will or
institutional nature, which is primarily designed to improve the image of the utility or the industry,
including advertisement which inform the public concerning matters affecting the Company’s
operations, such as, the costs of providing service, the Company’s efforts to improve the quality of
service, the Company’s efforts to improve and protect the environment. According to FERC, such
costs are properly includable in FERC Account 930.1 and are recoverable.                    According to
Ms. Tumminello, as contemplated by FERC, the fact that ETI is a monopoly has no bearing on the
recoverability of these costs.824


          OPC provided little support for its claim that costs covered by these project codes should not
be recoverable, essentially limiting the basis to the contention that ETI is a monopoly and ratepayers
should not be charged with such costs. ETI did provide the testimony of Ms. Tumminello, which
confirms that the costs are properly includable in FERC Account 930.1 and are, therefore,
recoverable. In the end, the weight of the evidence is in ETI’s favor. The ALJs recommend the
Commission reject OPC’s contention that costs covered by these project codes are not recoverable.


          2. Projects F3PPR56640 (Wholesale - EGS-TX) and F3PPR56920 (Wholesale - All
             Jurisdictions)

          As to Projects F3PPR56640 and F3PPR56920, Dr. Szerszen stated that these costs are
associated with assisting ETI’s wholesale customers in evaluating alternative energy supply and




823
      OPC Ex. 1 (Szerszen Direct) at 66.
824
      ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4-6.
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demand options and that ETI’s retail customers should not be charged for expenses associated with
ETI’s wholesale customers.825


          ETI witness Stokes noted that ETI has allocated costs to its single large wholesale customer
through its jurisdictional allocation in this rate case and, therefore, to disallow the costs in these two
project codes would essentially result in a double disallowance of those costs. She also explained
that the costs were properly allocable to ETI (keeping in mind that ETI then allocated costs to this
customer) as reasonable and necessary due to the need to have staff on hand to handle contract
negotiations and the like with this large wholesale customer.826


          The ALJs are persuaded by ETI’s argument that disallowing the costs associated with
Projects F3PPR56640 and F3PPR56920, which are already allocated to ETI’s single large wholesale
customer through its jurisdictional allocation, would constitute a double disallowance. Accordingly,
the ALJs recommend the Commission reject OPC’s challenge to these costs.


P.        Supply Chain Class

          Dr. Szerszen challenged two project codes that are primarily within the Supply Chain Class:
(1) F3PPH54075 (Business Development - TX) for a disallowance of $1,888; and (2) F5PCZSDEPT
(Supervision & Support - Supply) for a disallowance of $146. Dr. Szerszen claimed the costs
associated with these project codes should be disallowed because ETI is a monopoly and Texas
ratepayers should not have to pay for corporate image costs.827


          Ms. Tumminello testified that the costs are for advertising activities that are of a good will or
institutional nature, which is primarily designed to improve the image of the utility or the industry,
including advertisement which inform the public concerning matters affecting the Company’s
operations, such as, the costs of providing service, the Company’s efforts to improve the quality of
service, the Company’s efforts to improve and protect the environment, etc. According to FERC,

825
      OPC Ex. 1 (Szerszen Direct) at 73.
826
      ETI Ex. 66 (Stokes Rebuttal) at 6-9.
827
      OPC Ex. 1 (Szerszen Direct) at 66.
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such costs are properly includable in FERC Account 930.1 and are recoverable. According to
Ms. Tumminello, as contemplated by FERC, the fact that ETI is a monopoly has no bearing on the
recoverability of these costs.828


          OPC provided little support for its claim that costs covered by these project codes should not
be recoverable, essentially limiting the basis to the contention that ETI is a monopoly. ETI did
provide the testimony of Ms. Tumminello, which confirms that the costs are properly includable in
FERC Account 930.1 and are, therefore, recoverable. The ALJs go with the weight of the evidence,
which is in ETI’s favor. The ALJs recommend the Commission reject OPC’s contention that costs
covered by these project codes are not recoverable.


Q.        Transmission and Distribution Support Class

          Dr. Szerszen challenged three project codes that are included within the Company’s
Transmission and Distribution Support Class of affiliate costs: (1) F3PCT53130 (Operations
Manager, Claims Management) for a disallowance of $42,287.50; (2) F3PCTDAMAG (Damage
Claims Of Entergy Property) for a disallowance of $5,555; and (3) F3PCTPUBLC (Public Claims)
for a disallowance of $3,968. Dr. Szerszen’s rationale for disallowing 50 percent of the costs in each
of these codes is the same. She believes that ETI’s property damage and workers compensation
claims should be direct billed instead of allocated through a customer count-based allocator;
managerial and supervisory costs should be allocated to the jurisdictions based on the jurisdictional
direct charges; and the Company has not met its burden of proof as to these charges.829


          Ms. Tumminello addressed Project F3PCT53130, stating that workers’ compensation claims
are tracked by jurisdiction as Dr. Szerszen suggested, and are the basis for billing method
COMCLAIM. Project F3PCTWCOMP is used to capture the costs of workers’ compensation
claims, and bills to both regulated and non-regulated affiliates. Project F3PCT53130 captures costs
that are primarily for the oversight of the Entergy Companies’ Claims Management organization as
it relates to property damage and liability. These services benefit only the companies that serve

828
      ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4-6.
829
      OPC Exhibit No. 1 (Szerszen Direct) at 79-80.
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retail electric and gas customers. Since only the regulated utility operating companies (and not the
non-regulated companies) serve retail customers, it is appropriate to bill these costs to the regulated
companies based on their pro-rata share of total customers.830


          Projects F3PCTDAMAG and F3PCTPUBLC are addressed by ETI witness Corkran. With
respect to Project F3PCTDAMAG, Mr. Corkran stated that the costs associated with this project are
associated with the Public Claims employees in the Claims Management Organization. Those
employees pursue the recovery of claims allowed by law when the public inflicts damage to
Company property. The costs of this service are allocated among all of Entergy’s Operating
Companies through billing method CUSTEGOP, which allocates costs based on the number of
customers in each Operating Company. Dr. Szerszen claimed that the affiliate costs associated with
pursuing those claims should be directly charged to each Entergy Operating Company based on the
extent to which each claim pertains to the Operating Company instead of generally allocating the
costs to all utility customers. Mr. Corkran testified that the allocation methodology is appropriate
because the Public Claims employees provide knowledgeable, centralized, and consistent pursuit of
damage claims. The actual monies recovered for damage to ETI’s property are returned to ETI
ratepayers as credits against the cost of repairing those damaged facilities, i.e., the recoveries are not
allocated pursuant to CUSTEGOP. Only the Public Claims employees’ time and overheads are
allocated pursuant to CUSTEGOP, which is reasonable and appropriate because the overall time
spent by Public Claims employees in pursuing the recovery of claims is driven by the number of gas
and electric customers in each Operating Company.831


          With respect to Project F3PCTPUBLC, Mr. Corkran stated that the costs associated with this
project are related to Public and Auto Liability employees in the Claims Management Organization.
These employees pursue the resolution and settlement of damage claims made against the Operating
Companies in a timely and fair manner through denials, negotiations, and payments. Such claims
include allegations of damaged appliances due to voltage fluctuation, food loss due to power
outages, and damage caused by Company vehicles (e.g., mailboxes, fence posts, and automobiles).

830
      ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 10.
831
      ETI Ex. 48 (Corkran Rebuttal) at 13-15.
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This is an important process that ensures that only warranted and justifiable claims are paid. The
CUSTEGOP billing method is appropriate because the Public and Auto Liability employees provide
knowledgeable, centralized, and consistent resolution of damage claims. The actual payments
associated with ETI public damage claims are charged to ETI through the use of other project codes.
Only the Public and Auto Liability employees’ time and overheads are allocated pursuant to
CUSTEGOP, which is reasonable and appropriate because the overall time spent by Public and Auto
Liability employees in processing claims is driven by the number of gas and electric customers in
each Operating Company.832


            The explanations that ETI provides for the charges captured by these project codes and the
method of allocation employed makes sense to the ALJs. In a large organization, it is necessary to
have a group of people to process claims efficiently so that economies of scale can be realized; that
is what ETI is doing with these project codes. These costs benefit all companies within the Entergy
umbrella (or within the regulated entities portion as noted), so the allocation methodology employed
is appropriate. The ALJs recommend the Commission reject OPC’s challenge to the recovery of
these costs.


R.          Tax Services Class

            Dr. Szerszen proposed a 25 percent ($221,007) disallowance of costs billed to ETI from a
single project code in this Tax Services Class: Project Code F3PCF10445 (Entergy Consolidated
Tax Services). The costs in this project were incurred in the preparation, research, and other costs
associated with Entergy’s consolidated tax return. Dr. Szerszen testified that an assets-based
allocator is not appropriate for these costs and that the costs in the project should instead be directly
billed to each affiliate based on the time spent on preparing that affiliate’s income and expense
data.833


            Company witness Galbraith, who sponsors ETI’s Tax Services Class, stated that Dr. Szerszen
apparently believes that all costs associated with the preparation of Entergy’s consolidated tax return

832
      Id.
833
      OPC Ex. 1 (Szerszen Direct) at 63.
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are captured by this project code and are allocated, when they should be direct-billed. Most of the
costs associated with preparation of Entergy’s consolidated tax return, according to Ms. Galbraith,
are assigned to other project codes and are direct billed. Ms. Galbraith then explained that:
(1) 56 percent of the time that Tax Services spent on the Entergy consolidated tax return were direct
billed through other project codes to the affiliates; (2) the project code also captures costs for tax
research (both federal and state and local), monthly closing activities not specific to one legal entity,
tax training that is not jurisdiction specific, compliance with file retention policy, and administration
staff time; and (3) why the assets-based allocator is the best method for allocating these departmental
costs. According to Ms. Galbraith, the costs captured by this code are not susceptible to direct
billing.834

          The ALJs find that Dr. Szerszen did fail to consider that most of the costs of preparing
Entergy’s tax return are direct billed and that the costs covered by this project code are not
susceptible to such a billing, which is why they are allocated. The ALJs, therefore, recommend the
Commission reject OPC’s challenge to ETI’s allocation of these costs.


S.        Transmission Operations Class

          Dr. Szerszen challenged three project codes that are primarily within the Transmission
Operations Class: (1) F3PPTDHY19 (Dept. of Justice Investigations) for a disallowance of $765;
(2) F3PPTREORG (Transmission Re-Organization) for a disallowance of $3,661; and
(3) F3PPF30211 (ESI Transmission Bldg (Reclassification)) for a disallowance of $229,991.835


          Dr. Szerszen addressed Project F3PPTREORG (Transmission-Reorganization) and testified
that costs covered by this project were incurred in 2009 and 2010 and, therefore, are not recurring.836
Ms. Tumminello responds that, while these particular costs do not recur every year, they are



834
      ETI Ex. 26 (Galbraith Direct) at 10-12.
835
   Project F3PPTDHY19 (Dept. of Justice Investigations) was discussed in Section VIII.L. (Legal Services
Class) and will not be repeated here
836
      OPC Ex. 1 (Szerszen Direct) at 54, Schedule CAS-8.
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representative of normal recurring utility operations and do recur as necessary and, as such, they
should not be disallowed.837


          Dr. Szerszen testified that Project F3PPF30211 (ESI Transmission Bldg.) captures interest
costs after the ESI transmission building was placed in service. She contends that the costs are
reclassified pre-Test Year payments and post-Test Year interest costs that are not known and
measureable.838 Ms. Tumminello testified that Dr. Szerszen has misconstrued accounting entries.
She explains that these charges capture 12 months of interest payments and the annual bond fee
incurred only during the Test Year.839


          The ALJs find that the costs associated with Project F3PPTREORG are representative of
costs that recur every year and should not be disallowed. It appears to the ALJs that Dr. Szerszen
did misconstrue accounting entries in preparing her analysis of Project F3PPF30211and that the
charges in that project capture fees paid during the Test Year. Accordingly, the ALJs recommend
that OPC’s proposed disallowance be denied.


T.        Treasury Operations Class

          Dr. Szerszen challenged three project codes that are primarily within the Treasury Operations
Class: (1) F5PCZZI07P (Directors & Officers (EIM)) for a disallowance of $14,483;
(2) F3PCF25300 (Daily Cash Mgt Activities) for a disallowance of $7,286; and (3) F3PCF26022
(Financing & Short Term Funding) for a disallowance of $96,700.


          With respect to Project F5PCZZ107P (Directors & Officers (EIM)), Dr. Szerszen testified
that the directors and officers liability insurance subject to this project code is primarily aimed at




837
      ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 1.
838
      OPC Ex. 1 (Szerszen Direct) at 71.
839
      ETI Ex. 69 (Tumminello Rebuttal) at 15. See also Ex. SBT-R-5.
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benefiting shareholders, rather than ratepayers and, because ETI does not manage ESI’s operations,
it should not be responsible for indemnifying against shareholder lawsuits.840


          ETI witness McNeal stated that ESI provides essential administrative and operational
services to ETI on a daily basis. To do this, it must employ (and retain) qualified officers and
directors. These individuals must be assured that they can make reasoned decisions without fear of
personal liability and the manner to provide them this assurance is to purchase director’s and
officer’s liability insurance. Because ETI benefits from the services provided by the officers and
directors, ETI argues, it is appropriate to allocate a portion of the cost of the director’s and officer’s
liability insurance to ETI.841


          Dr. Szerszen addressed Projects F3PCF25300 (Daily Cash Mgt Activities) and F3PCF26022
(Financing & Short Term Funding), contending that these projects are duplicative of ETI-specific
financing and cash management activities; that these costs should be borne by Entergy shareholders;
and that the bank accounts-based and level of service-based allocators applicable to this projects are
not appropriate.842


          ETI responds that Project F3PCF25300 captures costs for activities performed by the Cash
Management Department for work associated with maintaining bank relationships, bank fee
analysis, administrative of bank systems and controls, and all other banking and cash management
activities that are general in nature. These are not specific to any one company, but are applicable to
all of the companies within the umbrella of the Entergy corporate family. There are Company-
specific activities that are charged directly to ETI under different project codes, and this constitutes
the majority of financing and cash management activities during the Test Year.                        For
Project F3PCF25300, the costs are driven by cash management products and services delivered to all
the Entergy companies. Because the number of transactions executed on behalf of each Entergy
company is directly related to the number of bank accounts by company irrespective of account size,


840
      OPC Ex. 1 (Szerszen Direct) at 59.
841
      ETI Ex. 61 (McNeal Rebuttal) at 7-8.
842
      OPC Ex. 1 (Szerszen Direct) at 74-75, Ex. CAS-15.
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billing method BNKACCTA, which allocates costs based on the number of open bank accounts is,
according to ETI, the appropriate method to allocate the costs of these services.843


          With respect to Project F3PCF26022, ETI explains that the project code captures costs for
managing Entergy companies’ liability portfolios comprised of Entergy company securities, bank
lines, and project financings. The work is performed for the benefit of all companies under the
Entergy corporate umbrella, not just ETI and is not duplicative of services performed for ETI. When
work is performed by ESI personnel that relates specifically to ETI, then ETI is charged directly
under a different project code. The services include analyzing and supporting general capital
structure policy, developing and analyzing general financial policies, investigating and evaluating
financing options generally that might prove beneficial for any or all Entergy companies, including
ETI, and facilitating ongoing administration related to all Entergy Operating Company financings.
Accordingly, ETI argues that it is appropriate to allocate a share of those costs to ETI. The costs of
this project are driven by the level of service needed to complete the project or activity. Allocator
LVSVCAL allocates costs based upon the overall service level of ESI. This allocation is appropriate
because ESI is providing the service and no one Operating Company alone benefits from the
services provided under this project code.844


          OPC appears to have taken too narrow a view with respect to these project codes. First, it
appears that where services are performed solely for ETI, they are charged to ETI through specific
project codes. The project codes that OPC challenges are for company-wide services that are
partially allocated to ETI. It is logical to assume that a certain level of services can be performed
more efficiently at a company-wide level and that Texas ratepayers will benefit by paying only the
allocated portion of those costs, as is done in these cases. The allocators chosen by ETI appear to
reasonably reflect the cost-causation. Therefore, the ALJs recommend that OPC’s challenge be
rejected.




843
      ETI Ex. 61 (McNeal Rebuttal) at 3-6; Tr. at 546.
844
      ETI Ex. 61 (McNeal Rebuttal) at 2-3; Tr. at 547-548.
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U.        Utility and Executive Management Class

          OPC challenges five project codes that are primarily within the Utility & Executive
Management Class: (1) F3PPCCS010 (Climate Consulting Services) for a disallowance of $19,821;
(2) F3PCCPM001 (Corporate Performance Management) for a disallowance of $173,867;
(3) F3PCC31255 (Operations-Office of the CEO) for a disallowance of $372,919; (4) F3PPCAO001
(Chief Administrative Officer) for a disallowance of $177,156; and (5) F3PPCOO001 (Chief
Operating Officer) for a disallowance of $74,485.


          As to the first, Project F3PPCCS010 (Climate Counseling Services), Dr. Szerszen testified
that these costs are incurred for the development of company-wide environmental policies,
procedures, and programs; that expenses are improperly allocated to the subsidiaries based on each
company’s fossil operating capacity; and, as a result, the non-regulated affiliates are not allocated
any environmental initiative expenses. She therefore recommended that 50 percent of this project’s
costs be disallowed.845


          ETI witness Stokes addressed Dr. Szerszen’s challenge to this project. Ms. Stokes explained
that although nuclear-related environmental projects are being pursued, they are not being pursued
using the project code referenced by Dr. Szerszen in her challenge. The costs for non-regulated
affiliates are charged to projects not included in ETI’s affiliate costs in this case. Non-regulated
affiliates use project codes specific to their businesses to maintain a separation of costs between
regulated and non-regulated Entergy subsidiaries.846


          For the remaining four project codes in this class, Dr. Szerszen stated that executive
management is primarily concerned with overall corporate functions rather than issues for any one
specific subsidiary, and there is no relationship between an assets-based allocator and executive
management.847


845
      OPC Ex. 1 (Szerszen Direct) at 62.
846
      ETI Ex. 66 (Stokes Rebuttal) at 5.
847
      OPC Ex. 1 (Szerszen Direct) at 56, 60.
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            ETI responds to these arguments by stating that the functions covered by these project codes
relate to the oversight of all system operations and the stewardship of corporate assets and that
because ETI is part of a corporate group, the allocated charges associated with these services are
relevant to ETI as part of that group of companies. Furthermore, ETI argues, the asset-based
allocator is appropriate because it reflects the cause of the costs incurred, in that, services provided
relate to the stewardship of all the corporation’s assets.848


            A corporation cannot function without executives, who are charged with the responsibility of
overseeing, among other things, the assets of the corporation. This is an important function that
Dr. Szerszen did not acknowledge in her testimony. The utility and executive management class
costs that she challenges are reasonable and necessary costs that are allocated to ETI based on a
logical allocator – the assets the executives manage. The ALJs recommend that OPC’s challenge be
rejected.


      IX.    JURISDICTIONAL COST ALLOCATION [Germane to Preliminary Order
                                    Issue No. 13]

            Jurisdictional cost allocation involves the proper method for allocating production costs
between ETI’s Texas retail customers and its wholesale customers, which are subject to FERC
jurisdiction. During the Test Year, ETI provided electric service to retail customers and to three
wholesale customers—including ETEC—under service agreements and rates approved by FERC.
ETEC is a partial requirements customer, and it will be ETI’s only wholesale customer during the
Rate Year. ETI estimated its cost of serving wholesale customers in a jurisdictional separation study
that split ETI’s cost of service between retail and the wholesale jurisdictions.849


            To calculate the wholesale cost allocation factor, ETI proposed the use of 150 MW for the
wholesale load. This results in a retail production demand allocation factor of 95.3838 percent. The
150-MW load represents the contractual minimum amount of capacity for which ETEC is obligated



848
      ETI Ex. 4 (Domino Direct) at 18-38; ETI Ex. 69 (Tumminello Rebuttal) at 9-11.
849
      Cities Ex. 4 (Goins Direct) at 4.
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to pay under its partial requirements agreement. No party contests this aspect of ETI’s proposed
allocation of costs between retail and wholesale customers.850


          However, Cities contest the type of allocation methodology used to assign demand-related
(fixed) production costs to each jurisdiction. In this proceeding, ETI used the A&E 4CP allocation
method. Although this is the same methodology ETI used in this proceeding’s class cost-of-service
study (to assign demand-related production costs to each retail customer class), ETI used a different
methodology – 12 Coincident Peak (12CP) – in its last rate case to assign costs between
jurisdictions.851


A.        A&E 4CP

          Kroger witness Kevin C. Higgins explained the A&E 4CP method:


          [T]he Average and Excess Demand method uses an average demand or total energy
          allocator to allocate that portion of the utility’s generating capacity that would be
          needed if all customers used energy at a constant 100 percent load factor. The cost
          of capacity above average demand is then allocated in proportion to each class’s
          excess demand, where excess demand is measured as the difference between each
          class’s individual peak demand and its average demand. In this manner, the
          incremental amount of production plant that is required to meet loads that are above
          average demand is assigned to the users who create the need for the additional
          capacity. . . . the A&E/4CP variant . . . uses 4 CP to measure excess demand,
          whereas the conventional version uses class non-coincident peak . . . .852

          ETI witness Myra L. Talkington also explained that the A&E 4CP method, noting that ETI’s
coincident peak demand is measured for the months of June through September. Ms. Talkington
recommends the A&E 4CP allocation because it “reasonably reflects the mix of the Company’s
customers and their respective electrical load characteristics and the relative cost incurred to serve



850
    ETI Ex. 7 (May Direct) at 23-24. Ms. Talkington used the 150 MW number sponsored by Mr. May, and
the associated energy use, to calculate the jurisdictional allocation factor. ETI Ex. 22 (Talkington Direct)
at 11-12.
851
      Cities Ex. 4 (Goins Direct) at 10.
852
      Kroger Ex. 2 (Higgins Cross Rebuttal) at 3 (footnotes deleted).
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such loads.”853 She also believes this allocation methodology provides a reasonable balance
between the contribution to the system peak and energy requirements.854


          As noted above, ETI’s use of A&E 4CP is a change from the 12CP methodology it used
when it operated within two states. Ms. Talkington testified that 12CP was appropriate in the past
because System Agreement costs were allocated between Entergy Operating Companies using 12CP.
The Texas retail portion of the production costs were then allocated between the retail classes using
the A&E 4CP methodology (as ETI is doing in this case). However, according to Ms. Talkington,
now that ETI operates in only one state, no jurisdictional allocation among states is necessary;
therefore, only one allocation methodology, i.e., A&E 4CP, should be used to allocate production
costs between the retail classes and the wholesale jurisdiction. Ms. Talkington testified that the
A&E 4CP methodology factors in year-round demand through the average and excess function and
also matches the allocator used to allocate costs within the retail class.855


          Cities opposes the use of A&E 4CP and suggest a 12CP methodology is preferable.
Commission Staff does not oppose ETI’s use of A&E 4CP. No other party takes a position on this
issue.


B.        12CP

          The12CP methodology allocates production capacity costs in proportion to each class’s
demands that occur on the date and time of ETI’s system peak in each of the 12 months.856 Cities
believe it is more appropriate for ETI to allocate fixed production costs between the wholesale
customers and Texas retail customers using 12CP. Cities witness Dennis W. Goins testified that the
12CP approach is consistent with the cost-of-service approach FERC typically uses to allocate
demand-related production costs reflected in wholesale rate schedules, and it is consistent with the
assignment of MSS-1 costs (as well as MSS-2 transmission costs) to ETI under the Entergy System

853
      ETI Ex. 23 (Talkington Direct) at 6; OPC Ex. 6 (Benedict Direct) at 17.
854
      ETI Ex. 23 (Talkington Direct) at 6.
855
      ETI Ex. 67 (Talkington Rebuttal) at 6-7.
856
      TIEC Ex. 3 (Pollock Cross Rebuttal) at 26.
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Agreement. Dr. Goins reviewed ETI’s Rate Year purchased power capacity costs month by month.
He determined that ETI’s heavy reliance on capacity purchases to serve retail and wholesale load,
and the relative stability of those projected monthly purchased power capacity costs, suggest that the
12CP method should properly split ETI’s demand-related production costs between the Texas retail
and wholesale jurisdictions.857


          Dr. Goins calculated Test Year 12CP allocation factors for the Texas retail and wholesale
jurisdictions, and provided them to Cities witness Karl Nalepa for inclusion in his jurisdictional
separation study. He determined the following:858


                         Jurisdiction         A&E 4CP           12CP
                      Texas Retail             95.3838%          94.6208%
                      Wholesale                 4.6162%           5.7923%
                      Total                        100%              100%


          In making this calculation, Dr. Goins used a loss-adjusted 150 MW (ETEC’s monthly
billing MW) as a proxy for the 12 monthly CPs. In his view, the 150 MW is indicative of ETI’s
capacity obligations to ETEC, and it reflects known and measurable changes compared to test-year
wholesale CPs (which would include CPs for wholesale customers that ETI no longer serves).859


          Cities point out that ETI previously allocated production costs to the wholesale jurisdiction
on a 12CP basis. ETI first requested that the Commission change the 12CP method in Docket
No. 37744.860 According to Cities, ETI’s request to change the 12CP methodology in Docket
No. 37744 is significant because ETI’s wholesale load consisted of Brazos Electric Cooperative, Inc.
(Brazos) and ETEC. The Brazos contract assigned Brazos’ share of ETI’s production costs based
upon a 12CP allocator. Thus, contends Cities, all costs that would have been over-allocated to retail

857
      Cities Ex. 4 (Goins Direct) at 10-12.
858
      Cities Ex. 4 (Goins Direct) at 12.
859
      Cities Ex. 4 (Goins Direct) at 10-12.
860
     The parties in that docket stipulated the majority of issues in the case, including issues relating to
jurisdictional allocation.
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customers would have been pocketed by ETI (if the 12CP allocator had changed). Cities argue that
ETI’s request to deviate from its approved 12CP allocator will result in retail customers subsidizing
production costs. Dr. Goins calculated that the 12CP allocation factor for ETI’s wholesale
jurisdiction is approximately 5.38 percent versus 4.62 percent under the A&E 4CP method.861 Cities
conclude that retail customers will subsidize the difference between the two allocators, which is
0.76 percent. Because the allocation is applied to all production costs, including purchased power
capacity costs, the 0.76 percent difference is significant, contend Cities.


          According to ETI, Cities’ arguments are based on a non-existent situation—the provision of
service to Brazos—and should be rejected. The ALJs acknowledge that ETI is no longer serving
Brazos. Dr. Goins noted such in his testimony. Rather, the basis for his recommendation was:
(1) the 12CP approach is consistent with FERC’s wholesale rate allocation; (2) the 12CP method is
used to derive each Entergy Operating Company’s load responsibility ratio and share of monthly
MSS-1 and MSS-2 charges; and (3) ETI’s purchased power capacity costs do not vary significantly
month to month. Although Ms. Talkington understood that the A&E 4CP methodology is the same
one used to allocate production costs between classes, TIEC witness Pollock noted that it is often not
appropriate to use the same allocation method for both jurisdictional and class allocations. He noted
that, in jurisdictional separation, allocations are between retail and wholesale entities, with
wholesale subject to FERC regulation.862 ETI did not fully explain why A&E 4CP is the best
methodology for allocation production costs between the retail and wholesale jurisdictions.
Dr. Goins’ and Mr. Pollock’s testimonies were ultimately more persuasive on this issue.
Accordingly, the ALJs recommend the use of 12CP to allocate capacity-related production costs
between the retail and wholesale jurisdictions.




861
      Cities Ex. 4 (Goins Direct) at 11-12.
862
   TIEC Ex. 3 (Pollock Cross Rebuttal) at 29. The ALJs acknowledge that Mr. Pollock does not contest
ETI’s use of the A&E 4CP jurisdictional allocation methodology—rather, his testimony was explaining why
12CP is not appropriate as an allocator among the different customer classes.
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      X.   CLASS COST ALLOCATION AND RATE DESIGN [Germane to Preliminary
                                Order Issue No. 1]

           ETI witness Talkington testified regarding the allocation methods for each of the major
function/classification cost categories used in the Company’s retail class cost-of-service study.
Ms. Talkington also sponsors ETI’s proposed rate design. Contested issues are set out below.


A.         Renewable Energy Credit Rider [Germane to Preliminary Order Issue No. 19]

           The Legislature has established a goal for the installation of an additional 5,000 MW of
generating capacity from renewable energy technology. It also set out annual goals for electric
utilities to meet on a cumulative basis in order to encourage the development of renewable energy
generation in Texas.. A utility may meet its annual goals by installing generation, by purchasing
capacity based on renewable energy technology, or by purchasing sufficient renewable energy
credits (RECs).863


           1. ETI’s Proposed Cost Recovery

           Staff witness William B. Abbott explained that the Company currently recovers its REC
costs through base rates. Each credit represents one megawatt-hour (MWh) of renewable energy
that meets certain criteria set forth in P.U.C. SUBST. R. 25.173(e), and these credits can be traded
among participants in the Texas market. ETI proposes to remove these costs from base rates and
implement a REC Rider to recover its projected REC costs. After the initial rider is established, the
REC Rider would be reset annually to recover projected REC costs for the upcoming year, adjusted
by any past over- or under-recovery and any revenue-related expenses.864 With the introduction of
the REC Rider, ETI would withdraw its current Renewable Portfolio Standard Calculation Opt-Out
Credit Rider, which provides a credit to offset the base rate REC costs for certain customers who are




863
      PURA §39.904(a) and (b).
864
      See ETI Ex. 31 (LeBlanc Direct) at 26.
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exempt from paying REC costs. These customers would instead be exempt from charges under the
proposed REC Rider.865


          ETI suggests that a rider is necessary because the level of REC costs incurred from year to
year is not known, and the cots are unknowable and very volatile. ETI witness Heather G. LeBlanc
testified that certain customers can opt out, and a rider is the most efficient manner to administer
such opt out.866


          Initially, ETI based its rates for the proposed rider on the Company’s Test Year renewable
energy credit costs, which were incurred on a Texas retail basis for the 12 months ending June 30,
2011. ETI requested $623,303 and, after applying the revenue-related expense factor of 1.01307,
proposed a revenue requirement of $631,450.867 In rebuttal testimony, Ms. LeBlanc stated that the
Company’s proposal should be updated to reflect the most current data available. She stated that
“events” since the Company’s initial filing in November 2011 caused costs for the Company to
increase.868 She calculated an updated amount of $1,145,043, which, when the revenue-related
expense factor is applied, results in an updated revenue requirement of $1,160,008.869 She believes
that the updated amounts further support the Company’s position that REC costs are volatile.


          2. Opposition to ETI’s Proposal

          Cities, OPC, State Agencies, and Commission Staff oppose ETI’s proposed REC Rider.


          State Agencies argue that ETI’s proposed REC Rider should be rejected because it deviates
from the Commission’s ratemaking policies and is inconsistent with PURA. State Agencies witness
Kit Pevoto testified that the proposed rider is not appropriate because: (1) the rider is piecemeal
ratemaking, which deviates from the Commission’s traditional ratemaking policies and is

865
      Staff Ex. 7 (Abbott Direct) at 11-12.
866
      ETI Ex. 31 (LeBlanc Direct) at 25.
867
      Id. at 24. This amount is then divided by all non-transmission level kWh sales.
868
      ETI Ex. 55 (LeBlanc Rebuttal) at 10-11.
869
      Id. at 11. This amount is then divided by all non-transmission level kWh sales.
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inconsistent with PURA; (2) the reconciliation (true-up) process in the proposed tariff is not
specifically provided for by PURA or PUC rule, or required to implement the REC process; (3) the
redetermination of rates in the proposed annual filings would be based on projected or estimated
costs, rather than historical test year costs; which is not in compliance with PURA or the
Commission’s rules; and (4) ETI has not justified the need to have a rate recovery for REC costs
outside of the traditional PURA base rate recovery. Ms. Pevoto explained that the traditional test
year cost of service ratemaking process, including regulatory lag, helps to match costs and revenues
and to provide incentives that balance the utility’s and its customers’ interests. The proposed REC
rider deviates from the traditional PURA rate-setting because it allows the Company to reset its rates
automatically each year without going through a comprehensive rate proceeding. In her view, the
rider would eliminate the regulatory lag incentive for ETI to prudently manage these costs because
the rider allows for annual cost recovery adjustments. Ms. Pevoto observed that various provisions
in PURA authorize riders for collection of other expenses, but no such provision exists for recovery
of REC expenses, even though the Legislature mandated that utilities be responsible for a certain
level of REC MWs. And she noted that if ETI’s REC expenses increase due to increases in total
REC MW requirements, ETI can request to include those increased costs in a future rate case.870


          In reference to Ms. LeBlanc’s rebuttal testimony that “events” caused ETI’s REC costs to
increase, State Agencies contend that ETI may have paid more for RECs during the Test Year
because it contacted suppliers only after the REC requirement was mandated. ETI acknowledged
that RECs were in the $1.10 to $1.25 range at the beginning of the year and then appreciated to over
$2.00 and peaked out at $2.55 in the first quarter of 2012. Moreover, one of the largest REC
suppliers unexpectedly withdrew its offers in March of 2011, which also led to price increases.
March 31 is the end of the compliance period, and the deadline may increase the volume of
purchases, which can add to price increases.871 State Agencies note that ETI did not participate in
the competitive REC market until February 2012 and bought its RECs near the peak price. State
Agencies contend that only Test Year costs of $623,303 should be included in base rates.



870
      State Agencies Ex. 2 (Pevoto Direct) at 6, 8-11.
871
      State Agencies Ex. 12, RFI.
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          Cities witness Karl Nalepa also opposed the REC Rider. He testified that the Commission
should not permit ETI to single out REC costs from base rates because it presented no evidence that
these costs should be treated differently than they are now. He added that RECs are not related to
fuel so much as they are related to retail sales and plant output. In his opinion, the Test Year amount
for REC of $633,985 should be included in base rates.872 Cities witness James Z. Brazell also
testified that ETI currently recovers a large portion of its revenues through non-fuel piecemeal
riders. While he believes some riders are necessary and appropriate, ETI’s general movement of cost
recovery from base rates to riders (as evidenced in this proceeding) is inconsistent with PURA and
the prohibition against piecemeal ratemaking.873


          OPC also opposed ETI’s proposed REC Rider on the basis that it constitutes piecemeal
ratemaking. OPC witness Nathan A. Benedict noted that in Project No. 35628, the Commission
rejected alternative mechanisms for the recovery of REC costs but reserved the right to consider the
issue at a later date.874 He stressed that, when rejecting alternative recovery mechanisms for REC
costs, the Commission recognized that REC costs are variable, that the purchase of RECs is
mandated by law, and that certain customers can opt out of the Renewable Portfolio Standard
program. Thus, in Mr. Benedict’s view, the Commission has already rejected the arguments
advanced by ETI here. He added that ETI did not indicate a negative and substantial impact as a
result of transmission customers opting out of the Renewable Portfolio Standard program, and ETI
appears to be currently administering the program effectively without REC Rider. In short,
Mr. Benedict concluded that costs related to renewable energy credits should be recovered through
base rates, and ETI’s current opt-out rider should continue as the vehicle for ETI to handle
transmission-level opt-outs.875


872
   Cities Ex. 6 (Nalepa Direct) at 30-32. Mr. Nalepa’s figure of $633,985 differs from that the figure of
$623,303 found in ETI’s testimony at ETI Ex. 31 (LeBlanc Direct) at 24 and State Ex. 9.
873
      Cities Ex. 1 (Brazell Direct) at 14-16.
874
    OPC Ex. 6 (Benedict Direct) at Ex. NAB-8, Project No. 35628, Rulemaking Relating to Industrial
Customer Opt-Out of Renewable Portfolio Standard, Order at 6 (December 4, 2008).
875
    OPC Ex. 6 (Benedict Direct) at 37-41. ETI currently has a Renewable Portfolio Standard Calculation
Opt-Out Credit Rider to credit REC costs collected in base rates from transmission level customers who have
opted out of the program.
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          Commission Staff also opposes ETI’s request, stating that it amounts to unauthorized
piecemeal ratemaking that should be disallowed. In Staff’s view, the existing opt-out rider should be
maintained but updated to reflect the test year data used to set the ETI’s base rates. Because ETI’s
proposed rider would include a true-up provision that would guarantee recovery of all of its REC
costs, Staff witness Abbott testified that it would violate PURA § 36.051, which provides the utility
a reasonable opportunity to earn a reasonable return on invested capital but does not guarantee full
recovery of all costs. Mr. Abbott acknowledged that the Legislature has authorized the recovery of
certain specific costs outside of base rates, but no such authorization exists for the recovery of REC
costs.876


          In addition, Mr. Abbott criticized the proposed REC rider because in the future it would
allow prospective recovery of estimated REC costs. He believed that such an arrangement would
eliminate any regulatory lag and thus eliminate any incentive for ETI to minimize the costs of
purchasing the required RECs.877 Mr. Abbott also pointed out that the proposed rider contains a
single rate for all customer classes and includes a “revenue related expense factor,” which increases
the overall rider revenue requirement to, in part, account for projected uncollectable bills.878 This
would shift the costs of uncollectable bills from customer classes with greater bad debt onto
customer classes with lower bad debt. Further, Mr. Abbott stated, the proposed true-up portion of
the REC Rider would eliminate the need for a bad debt factor, as any actual under-collected amounts
would carry forward and could be recovered in future filings. Also, the single rate could result in
cost-shifting between customer classes, as over- or under- recoveries resulting from billing
determinant forecast error would vary by customer class. Finally, Mr. Abbott stated, the ETI’s
proposed billing determinants are based on a historical year. But if load grows over the long term,


876
   Staff Ex. 7 (Abbott Direct) at 12-13. Mr. Abbott cites to PURA §§ 36.203 (Fuel Cost Recovery), 36.205
(Purchased Power Cost Recovery), 36.209 (Transmission Cost Recovery), 36.210 (Distribution Cost
Recovery), 39.107(h) (Advanced Meter Deployment Surcharge), 39.461 (Hurricane Reconstruction Costs),
39.905(b)(1) (Energy Efficiency Cost Recovery).
877
    While the price of RECs at any point in time are set by the market, presumably a purchaser has some
ability to seek relatively better terms—such as making an effort to accurately forecast the number of credits
required and perhaps purchasing or contracting to purchase available credits beforehand if prices are
favorable, seeking volume discounts, banking excess credits when prices are favorable, etc.
878
      Schedule Q-8.8 at 45.4.
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this will lead to persistent over-recovery of the REC Rider revenue requirements, as Rate Year
billing determinants will tend to exceed the historical billing determinants systematically.879


          Based on these concerns, Mr. Abbott recommended that the Commission deny ETI’s request
for a REC Rider, and that the ETI’s Test Year REC costs of $623,303 be included in base rates.
Additionally, he recommended that the Renewable Portfolio Standard Calculation Opt-Out Credit
Rider should be maintained; however, the credit rates should be updated to reflect the Test Year data
used to set ETI’s base rates. In the alternative, if the Commission approves the REC Rider requested
by ETI, Mr. Abbott recommended the following changes from the Company’s request:


          ¾       The REC Rider should be set every year to collect the previous year’s actual REC
                  costs (instead of projected REC costs), plus any over- or under- recovery from prior
                  periods.

          ¾       The previous year’s actual REC costs should be allocated to each customer class
                  based upon each class’s actual energy usage over the time period for which the RECs
                  were acquired.

          ¾       Any over- or under- recovery balances should be tracked by each customer class, and
                  thus a separate REC Rider rate should be calculated for each customer class based on
                  that class’s allocated REC costs adjusted by that class’s over- or under- recovery
                  balance.

          ¾       The REC Rider rates should be calculated using billing determinants based upon
                  ETI’s best forecast of each customer class’s energy usage over the rider’s Rate
                  Year.880

          3. ETI’s Response

          ETI contends that adoption of the rider does not result in piecemeal ratemaking because these
are the types of costs that the Company cannot control. Ms. LeBlanc believes that there is a greater




879
      Staff Ex. 7 (Abbott Direct) at 13-14.
880
      Staff Ex. 7 (Abbott Direct) at 14-15.
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risk of over-recovery of REC costs through base rates than there would be under the proposed
rider.881


          As to the issue that the Company would be disincentivized to purchase RECs at an
appropriate time, ETI claims that the proposed rider has a true-up mechanism that would allow for
review. ETI disputes State Agencies’ claims that ETI could have purchased RECs at a lower level at
other points in the year, stating there is no evidence that the Company could have bought RECs at a
lower level at other points in the year.


          Finally, ETI takes issue with the parties’ argument that there is no statutory recovery for
REC costs outside of base rates. ETI argues that there is no statutory authority requiring the
Company to refund costs to opt-out industrial customers. According to ETI, no explicit statutory
authority is necessary, and the parties have failed to establish that any harm would result from
implementation of the rider.


          4. ALJs’ Analysis

          The ALJs are persuaded by the testimonies of Staff and intervenor witnesses Pevoto, Nalepa,
Abbot, Benedict, and Brazell that ETI’s proposed REC rider should be rejected. The testimony
supports a finding that adoption of the rider results in piecemeal ratemaking. ETI’s argument that
costs are volatile and, therefore, should be isolated and recovered in a manner similar to an annual
fuel factor filing was not supported by sufficient evidence. Additionally, the ALJs agree that the
proposed rider eliminates any incentive for ETI to minimize the costs of purchasing the required
RECs. ETI proffered unconvincing argument and insufficient evidence that standard cost recovery
was insufficient for ETI to recover its total REC costs and a reasonable return.


          The ALJs further find that the Test Year expense of $623,303 should be used for setting rates
in this case.882 ETI failed to proffer sufficient evidence and argument to support any increase to its

881
      ETI Ex. 55 (LeBlanc Rebuttal) at 11.
882
   This is the amount referenced in Ms. LeBlanc’s testimony at ETI Ex. 31 at 24 and confirmed in State
Agencies Ex. 9.
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initial request through rebuttal testimony. As recommended by Staff witness Abbott, the Renewable
Portfolio Standard Calculation Opt-Out Credit Rider should be maintained, with an adjustment to the
credit rates to reflect the Test Year data used to set ETI’s base rates.


B.        Class Cost Allocation [Germane to Preliminary Order Issue No. 14]

          A cost-of-service study is an analysis used to determine the responsibility for a utility’s costs
for each customer class. Thus, it determines whether the revenues a class generates cover that
class’s cost-of-service. A class cost-of-service study separates the utility’s total costs into portions
incurred on behalf of the various customer groups. Most of a utility’s costs are incurred to jointly
serve many customers. For purposes of rate design and revenue allocation, customers are grouped
into homogeneous classes according to their usage patterns and service characteristics.


          The parties generally agreed that ETI’s cost-of-service study comported with accepted
industry practices, but some parties had issues with specific items discussed below.


          1. Municipal Franchise Fees

          Municipal Franchise Fees (MFF) are charges for a utility’s use of municipal rights-of-way.
The charges are levied by municipalities based on the amount of electricity sold within the municipal
boundaries. They are also referred to as street rental taxes. The MFF charged to ETI are based on
ordinances passed by the cities in which ETI makes retail sales. Different cities have enacted
different levels of MFF on in-city kWh sales, ranging from 0.0956¢ to as much as 0.2644¢ per
kWh.883 For the portion of fees ETI collects through base rates, ETI proposes to allocate among
customer classes based on customer class revenues relative to total revenues.884 Once MFF costs are




883
   TIEC Ex. 1 (Pollock Direct) at 52 and Ex. JP-9. Nineteen cities also charge MFF through separate
“Incremental Franchise Fee Recovery” Riders. These incremental MFF are not included in ETI’s proposed
revenue requirements in this case. TIEC Ex. 1 (Pollock Direct) at 53.
884
      Schedule P-13 at10, lines 32-33; the allocation factor “RSRRTOA-Total” is rate schedule revenue.
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allocated to the rate classes, ETI proposes to collect the costs from all customers regardless of their
geographic location.885


          ETI proposes the same allocation and collection of MFF in this case as was approved by the
Commission in Docket No. 16705, ETI’s last litigated rate case.886 The positions of the parties, as
set out in testimony and briefs, are listed below:


Party/Precedent          MFF Allocation Between                Collection of MFF Expenses From:
                         Customer Classes By:
ETI                      Total revenues                        All customers
Cities                   Total revenues                        All customers
OPC                      kWh sales in city                     All customers
Staff                    kWh sales in city                     All customers
TIEC                     Franchise fee payments in city        Only from municipal customers
Docket No. 16705         Total revenues                        All customers


                      (a) MFF Allocation Between Customer Classes

          Cities and ETI recommend adoption of ETI’s proposal to allocate to customer classes based
on total rate schedule revenues, which the Commission approved in Docket No. 16705. ETI notes
that it is following Commission precedent, and it opposes the use of different allocation factors for
these FERC accounts: Account 408.152, Franchise Tax State; Account 408.154 Franchise Tax
Local; and Account 408.163, Street Rental.


          OPC witness Benedict testified that MFF should be allocated on the basis of in-city kWh
sales, without an adjustment for the MFF rate in the municipality in which a given kWh sale
occurred. Staff witness Abbot concurs. Stated differently, Messrs. Benedict and Abbot suggest


885
      OPC Ex. 8 (Benedict Cross Rebuttal) at 9.
886
   Application of Entergy Gulf States, Inc. for Approval of Its Transition to Competition Plan and the Tariffs
Implementing the Plan, and for the Authority to Reconcile Fuel Costs, to Set Revised Fuel Factors, and to
Recover a Surcharge for Underrecovered Fuel Costs, Docket No. 16705, Second Order on Rehearing at 98
(FoF 224) (Oct. 13, 1998).
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allocating MFF relative to each class’s inside-city kWh sales with the same MFF per unit cost (i.e.,
0.1965¢ per kWh) for all customer classes.887 Mr. Benedict noted that this allocation method is
based on Commission precedent, as indicated in the recent CenterPoint rate case, Docket No. 38339:


          CenterPoint’s allocation of municipal franchise fees to the customer classes based
          upon in-city kilowatt-hour (kWh) sales and collection of the fees from all customers
          within the customer class is reasonable and consistent with Commission precedent.888

Mr. Benedict also noted that allocating on the basis of in-city kWh sales is consistent with PURA
§ 33.008(b).889


          Commission Staff supports Mr. Benedict’s analysis. Staff points out that PURA § 33.008(b),
which authorizes the collection of municipal franchise fees, states that “[t]he compensation a
municipality may collect from each electric utility . . . shall be equal to the charge per kilowatt hour .
. . times the number of kilowatt hours delivered within the municipalities boundaries.”890 According
to Staff, PURA § 33.008(b) plainly links the amount of municipal franchise fees to each class’s
in-city kWh sales. Moreover, the Commission has an established policy of allocating municipal
franchise fees based on in-city kWh sales.891 According to Staff, the Commission should reaffirm

887
   See OPC Ex. 7 (Benedict Cross Rebuttal) at 4-5; Staff Ex. 7 (Abbott Direct) at 22; TIEC Ex. 3 (Pollock
Cross Rebuttal) at 34.
888
    OPC Ex. 6 (Benedict Direct) at Ex. NAB-1, Application of CenterPoint Electric Delivery Company, LLC,
for Authority to Change Rates, Docket No. 38339, Order on Rehearing at 34, (FoF 179) (June 23, 2011).
889
      OPC Ex. 7 (Benedict Cross Rebuttal) at 5.
890
      PURA § 33.008(b)(emphasis added).
891
   Application of TXU Electric Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA
§ 39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22350, Order at FoF 156
(Oct. 4, 2001). The Commission reached an identical conclusion in Application of Reliant Energy HL&P for
Approval of Unbundled Cost of Service Rate Pursuant to PURA 39.201 and Public Utility Commission
Substantive Rule 25.344, Docket No. 22355, Order at FoF 222A (Oct. 4, 2001). More recently, Application of
CenterPoint Electric Delivery Company, LLC, for Authority to Change Rates, Docket No. 38339, Order on
Rehearing at FoF 179 (June 23, 2011) (stating that “CenterPoint’s allocation of municipal franchise fees to the
customer classes based upon in-city kilowatt-hour (kWh) sales and collection of the fees from all customers
within the customer class is reasonable and consistent with Commission precedent.”).
Staff notes in their initial brief that the Commission has further indicated that this allocation should be
conducted without any adjustment for differences in the rates charged by individual municipalities within a
utility’s service territory. Application of AEP Texas Central Company for Authority to Change Rates, Docket
No. 33309, Order on Rehearing at FoF 150 (Mar. 4, 2008) (stating in connection with a proposed municipal
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this precedent in this case by allocating ETI’s MFF to each customer class on the basis of in-city
kWh sales.


          TIEC witness Pollock disagrees with OPC’s and Staff’s proposed allocation method,
although Mr. Pollock stated their proposal was better than ETI’s proposed allocation. He believes
OPC’s and Staff’s proposal fails to recognize the different MFF rates charged by cities. Because
cities that have a preponderance of industrial sales generally charge lower MFF rates, this proposal
would require LIPS customers to pay 0.1965¢ per kWh, which is more than the weighted average
MFF cost to the LIPS class of 0.1612¢ per kWh. Thus, Mr. Pollock argues that this would require
LIPS customers to subsidize other customer classes and would not be consistent with cost causation.
Mr. Pollock thought his proposal to allocate MFF by city by class resulted in each customer class
paying only the MFF expenses actually incurred.892


          The ALJs find OPC’s and Staff’s proposed allocation methodology best comports with
PURA § 33.008 and Commission precedent. As noted by Mr. Benedict, PURA was amended after
the Commission’s decision in Docket No. 16705, which allocated MFF on the basis of rate schedule
revenue. PURA § 33.008 expressly calls for a kWh basis for allocation and this is confirmed in the
cases litigated since Docket No. 16705, which were cited by Commission Staff. Accordingly, the
ALJ recommend that MFF be allocated on the basis of in-city kWh sales, without an adjustment for
the MFF rate in the municipality in which a given kWh sale occurred.


                      (b) MFF Collection

          All parties except TIEC recommend that the Commission approve ETI’s proposed allocation
of franchise fee rentals to all customers. Cities witness Mr. Brazell testified that franchise fees are in
the nature of a rental, not a tax, and like all rental charges ETI incurs, the expense should be spread
among all customers. He stated that MFF charges have always been collected from all customers,
whether or not they take service within the corporate limits, except for the limited incremental


franchise fee expense rider that “[h]aving different rates in each municipality in TCC’s service territory is
contrary to the Commission’s desire for uniform, simple rates”).
892
      TIEC Ex. 3 (Pollock Cross Rebuttal) at 8, 33-35.
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franchise fees specifically addressed by PURA § 39.456. Mr. Brazell explained that electrical
facilities within ETI’s system are physically interconnected and electrically synchronized. The
facilities located within a city’s boundaries are not isolated physically or electrically from the
facilities outside the city limits. Rather, they are tied to one another and function as a single
integrated system, and ETI’s facilities inside each city benefit all customers in ETI’s service area,
whether or not those customers are within the city. Therefore, Mr. Brazell recommended that the
Commission approve ETI’s request to recover MFF in base rates from all customers.893


          Mr. Benedict holds the same opinion. He stated that the Commission’s policy to collect MFF
from all customers within a customer class is also consistent with the concept that MFF are system
costs that are rightly paid by all customers taking service from the system. He explained that MFF
are paid by a utility to municipalities for use of the municipalities’ rights-of-way. Because these
rights-of-way are necessary to operate an integrated electric delivery system from which all
customers benefit, regardless of geographic location, Mr. Benedict stated that MFF should be
collected uniformly from all customers within a given rate class. He stressed that the Commission
agreed with this reasoning in Docket No. 16705, where the Commission concluded:


          Current cost of services studies are not based on geographical differences. Classes
          are not divided based on geography, and industrial sites are not self-sufficient
          islands. The use of city streets and property enables [EGSI] to have an integrated
          utility system from which all ratepayers benefit.894

          Mr. Pollock objected to the proposals by Mr. Brazell and Mr. Abbott. He stated that
Mr. Brazell’s recommendation to adopt ETI’s proposed MFF allocation should be rejected because
there is no evidence that outside city customers benefit from ETI’s use of city streets and rights-of-
way or that the benefits are evenly distributed between inside and outside city customers. Further,
according to Mr. Pollock, the standard used in class cost-of-service studies is cost causation, not




893
      Cities Ex. 1 (Brazell Direct) at 28-32.
894
    OPC Ex. 6 (Benedict Direct) at Ex. NAB-2, Docket No. 16705, Second Order on Rehearing at 98,
(FoF 224).
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benefits, and he believes allocating MFF based on outside city usage is contrary to cost causation
principles.895


          The ALJs recommend adoption of ETI’s proposal to collect costs from all customers taking
service from the system. The ALJs find persuasive the fact that MFF is compensation for the use of
municipalities rights-of-way, which is used to operate an integrated electric delivery system from
which all customers benefit.


          2. Miscellaneous Gross Receipts Taxes

          Miscellaneous gross receipts taxes (MGRT) are state taxes imposed on each utility
company’s taxable gross receipts derived from sales in an incorporated city or town having a
population of more than 1,000. Like MFF, these taxes are levied only on sales within the cities. ETI
proposes to allocate MGRT to all retail customer classes based on customer class revenues relative
to total revenues.896


          TIEC objects to ETI’s allocation of MGRT based on class revenues for the same reasons
stated for ETI’s allocation of MFF. It argues that these costs should be allocated and charged to
customers within the municipalities to which the MGRT applied.


          The allocation of MGRT is similar to the allocation of MFF and should be similarly applied.
For the reasons set out above and to ensure consistent treatment, the ALJs do not recommend the
direct method of allocation suggested by TIEC. Rather, these costs should be allocated to the rate
classes according to ETI’s cost of service study.




895
      TIEC Ex. 3 (Pollock Cross Rebuttal) at 7, 32-33.
896
      ETI Ex. 3, Schedule P-13 at 10, line 34.
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          3. Capacity-Related Production Costs

                     (a) Allocation Methodology

          ETI proposes to allocate capacity-related production and transmission costs to the retail
classes on the basis of A&E 4CP. As noted by TIEC and Commission Staff, this allocation
methodology is consistent with the method ETI used in Docket No. 16705, its last contested rate
proceeding:


          Finding of Fact No. 221. The continued use of the A&E 4CP allocator is the most
          reasonable methodology for allocating production and transmission plant among
          classes. The A&E 4CP allocator sufficiently recognizes customer demand and
          energy requirements and assigns cost responsibility to peak and off-peak users. It
          best recognizes the contribution of both peak demand and the pattern of capacity use
          through the year.

          Finding of Fact No. 222. The A&E 4CP method is also preferable because it is
          devoid of any double counting problem.897

          ETI witness Ms. Talkington explained that the A&E 4CP allocation is appropriate because it
is a method that reasonably reflects the mix of the Company’s customers, their respective electrical
load characteristics, and the relative costs incurred to serve such loads. She testified that the
A&E 4CP method provides a reasonable balance between the two primary costing concerns:
contribution to the system peak and energy requirements. While the contribution made to the system
peak is inherently recognized with the use of the average four coincident peaks, energy is also
recognized by reflecting the average demands.898


          OPC witness Benedict proposed the use of the average and single coincident peak (A&P)
method to allocated production (and transmission costs, which are discussed in the section below)


897
      Docket No. 16705, Second Order on Rehearing at 97, FoF 221 and 222 (Oct. 14, 1998).
898
    ETI Ex. 22 (Talkington Direct) at 5. As noted previously, A&E 4CP is developed by adding each rate
class’s average demand for the test year (the “average” component representing the rate class’s average
energy consumption), weighted by the ETI system load factor, to each rate class’s amount of average
coincident peak demand for the months of June through September in excess of its average demand, weighted
by one minus the ETI system load factor.
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among retail classes. As noted in the discussion concerning jurisdictional allocation, A&E 4CP is a
variant of the A&E allocator. Mr. Benedict believes that A&E 4CP fails to properly assign cost
responsibility to both peak and off-peak usage.899 Instead, he found that the A&E 4CP allocator
results in the same factors reached by the 4CP method, which means that A&E 4CP assigns cost
responsibility only to peak demand and not to off-peak demand. He believes that the A&P
methodology is the proper plant allocator because it takes into account both peak usage and off-peak
usage patterns.900


            Mr. Benedict’s methodology and recommendation was disputed by Kroger witness Higgins.
He indicated that the A&E method does not converge to a CP result. Rather, the A&E method
addresses a fundamentally important question in production cost allocation—once capacity needed
to serve the average demand on the system is accounted for, how does the regulator fairly assign the
responsibility for the additional or excess capacity that is needed to meet the various capacity
requirements (placed on the system by each customer class). Mr. Higgins concluded that the A&E
method makes an objective and reasonable allocation. However, he did not advocate changing
ETI’s use of A&E 4CP.901


            Mr. Higgins explained that:


            [T]he Average and Excess demand method begins by allocating a portion of costs on
            the basis of average demand—or energy. The remaining (or “excess”) capacity
            needs of the system are then allocated to classes based on peak usage—class NCP in
            the case of the “standard” approach, 4 CP in the case of the A&E/4CP method. In
            contrast, the A&P method proposed by Mr. Benedict, which is classified by the
            NARUC Manual as a “Judgmental Energy Weighting” approach, incorporates a
            subjective determination that includes the full value of average demand both in the
            “average” component of the A&P calculation as well as in the peak component of
            that calculation.902


899
    Mr. Benedict performed a mathematical proof that he believed demonstrated that the A&E 4CP allocator
is nearly identical to the 4CP allocator. OPC Ex. 6 (Benedict Direct) at 21-22.
900
      Id.
901
      Kroger Ex. 2 (Higgins Cross Rebuttal) at 4-5.
902
      Id. at 6 (emphasis in originial).
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          TIEC witness Pollock also disputed Mr. Benedict’s proposed methodology, stating that A&P
does not reflect cost causation and is not reasonable for ETI. He believes that Mr. Benedict’s
support of the A&P method is based on an oversimplification of the planning process. He also noted
that A&E is recognized in the NARUC Electric Utility Cost Allocation Manual and has been
repeatedly used by the Commission.903


          The following calculations performed by Messrs. Benedict and Higgins demonstrate the
different results stemming from the allocation methodologies:904


                                   ETI                  OPC                Kroger
                                 Proposed           Recommended           Standard        Alternative
        Rate Class              A&E/4CP (%)           A&P (%)               A&E              12CP
 Residential                         47.4494              40.1181            48.4013            43.4768
 Small General Service                2.0990               2.0595             2.7209             2.0169
 General Service                     18.0259              19.4933            18.5183            18.6122
 Large General Service                7.0794               8.3822             6.6558             7.4339
 Lg. Indust. Power Serv.             20.4401              25.5485            20.2122            22.9417
 Total Lighting                       0.2900               0.2768             0.4042             0.1394
 Total Texas Retail                  95.3838              95.8784            96.9127            94.6208
 Total Wholesale and                  4.6162               4.1216             3.0873             5.3792
 Wheeling
 Total Company                        100.0000            100.0000          100.0000           100.0000


          The ALJs recommend the use of A&E 4CP to allocate capacity-related production costs, as
proposed by ETI. The weight of the evidence as well as Commission precedent does not support the
methodology proposed by Mr. Benedict. A&E 4CP was approved for the Company in Docket
No. 16705, and the extensive testimonies (which included calculations and graphs) of
Messrs. Higgins and Pollock indicate that, not only is the methodology frequently adopted by the
Commission, it is also a standard and reasonable methodology. As noted by ETI, it reasonably
reflects the mix of the Company’s customers and their respective load characteristics and the relative


903
   TIEC Ex. 3 (Pollock Cross Rebuttal) at 12-14, citing the NARUC Electric Utility Cost Allocation Manual,
January 1992.
904
      OPC Ex. 6 (Benedict Direct) at 25; Kroger Ex. 2 (Higgins Cross Rebuttal) at 5.
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costs incurred to serve such loads. It recognizes the contribution of both peak demand and the
pattern of capacity use throughout the year.905 It also recognizes that ETI, like all Texas utilities, is a
summer peaking utility. The ALJs recommend that ETI’s allocation of capacity production costs be
adopted.


                      (b) Reserve Equalization Payments

            A subset of the Company’s requested capacity-related production costs relate to reserve
equalization payments made by the Company pursuant to the Entergy System Agreement (Service
Schedule MSS-1). The System Agreement, which is approved by the FERC, prescribes a method by
which each Entergy Operating Company’s share of Entergy system reserves are calculated. ETI, as
one of the Operating Companies, is responsible to provide the system with its allocated share of
system reserves. Some Entergy Operating Companies own less than their share of system reserves
and are considered “short” with respect to generation capability. Companies that own more than
their share are considered “long” companies. Short companies make payments to long companies
pursuant to the terms of the System Agreement. Because ETI is a short company, it makes reserve
equalization payments which are included in the cost of service.906


            ETI allocates MSS-1 payments using A&E 4CP. Mr. Benedict argues that this allocation
method is not consistent with the way costs are incurred, as ETI does not make MSS-1 payments on
the basis of A&E 4CP. According to Mr. Benedict, ETI incurs costs by being short with respect to
system reserves—the payment is simply the number of MW by which it is short, multiplied by a
$/MW rate as determined by a contract formula. The degree to which ETI is short is determined by
comparing its generation capability to its allocated share of system reserves. Total system reserves
are allocated to the other Operating Companies on the basis of the Responsibility Ratio. Thus, as
determined by the Responsibility Ratio, ETI’s share of system reserves relative to its generating
capability is what causes ETI to make MSS-1 Reserve Equalization payments.907


905
      See Docket No. 16705, Second Order on Rehearing at FoF 221 (Sept. 4, 1998).
906
      OPC Exhibit No. 6 (Benedict Direct) at 29-30.
907
      Id.
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           Mr. Benedict concluded that, because Reserve Equalization payments are incurred on the
basis of ETI’s Responsibility Ratio, which is a rolling 12CP allocator, the payments should be
allocated to ETI’s rate classes on a similar basis. As a result, he recommended that Reserve
Equalization payments be allocated on the basis of 12CP.908


           According to OPC, Mr. Benedict’s proposal for allocating MSS-1 payments has been
criticized because 12CP measures class demands at ETI’s peak monthly demands whereas the
Responsibility Ratio is measured at the Entergy system’s peak monthly demands. OPC agrees that
12CP uses peak hours that may differ from those used to compute the Responsibility Ratio, but
contends that the Company fails to mention that the A&E 4CP method it uses to allocate MSS-1
payments is also subject to the same critique. When choosing between the 12CP allocator and the
A&E 4CP allocator for the purpose of allocating reserve equalization payments, OPC believes 12CP
is more desirable. ETI’s contributions to the Entergy system’s peaks in all 12 months, not just the
four summer months, determine ETI’s share of Entergy system reserves. ETI’s share of system
reserves, relative to its generation capability, is what causes reserve equalization payments to the
other Entergy Operating Companies. Moving to a 12CP allocation for MSS-1 payments aligns cost
allocation more closely with cost causation.


           TIEC witness Pollock explained that the Entergy System Agreement is regulated by the
FERC, which does not control the rate design policy applicable to Texas retail customers under
Commission jurisdiction. He views the System Agreement as an accounting mechanism to equalize
the benefits and costs associated with interconnected operation and joint planning. In his opinion, it
is not relevant to determining which production capacity allocation method best reflects cost
causation for Texas retail customer. According to Mr. Pollock, the MSS-1 payments are no different
in concept from the costs associated with ETI’s high-voltage transmission lines, which are allocated
on an A&E 4CP basis. He further indicated that the 12CP method ignores the reality the ETI is a
predominantly summer peaking utility.909



908
      Id. at 31.
909
      TIEC Ex. 3 (Pollock Cross Rebuttal) at 27-29.
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          The ALJs do not find sufficient support to allocate the reserve equalization payments
differently than other capacity-related production costs. For the same reasons noted in the section
above, the ALJs find the weight of the evidence supports allocation using A&E 4CP. While 12CP is
a reasonable methodology for jurisdictional separation between retail and wholesale entities, the
evidence does not support this methodology for allocation of reserve equalization payments.


          4. Transmission Costs

          As noted above, ETI also allocates transmission costs using the A&E 4CP methodology.
Again, TIEC and Staff cite to the Commission’s decision in Docket No. 16705, which adopted the
A&E 4CP approach for both production and transmission costs. OPC witness Benedict, however,
proposes allocating transmission plant using A&E methodology that he proposed for the allocation
of production plant.910

          TIEC argues that methodologies similar to Mr. Benedict’s proposal have been repeatedly
rejected by the Commission, and the A&E 4CP methodology has been repeatedly approved. TIEC
suggests that Mr. Benedict offers no rationale for a different result for transmission costs. According
to TIEC, the rationale that he offers for using the A&P method for production costs—the potential
trade-off between capital costs and fuel costs—is entirely absent with respect to transmission plant.
Mr. Benedict does not even assert that such trade-offs exist. Rather, the only basis he offers for
using the average and peak methodology is his assertion that the A&E 4CP allocator
“mathematically reduces to a 4CP allocator.”911 TIEC points out that the Commission, by rule, has
adopted the 4CP method for the allocation of transmission plant within ERCOT.912


          ETI witness Talkington indicated the same reasons and rationale for using the A&E 4CP
methodology to allocate transmission costs as she noted for capacity-related production costs.913


910
      OPC Ex. 6 (Benedict Direct) at 26-28.
911
      TIEC Initial Brief at 68, citing OPC Ex. 6 (Benedict Direct) at 27.
912
    P.U.C. SUBST. R. 25.192 specifically provides that transmission costs are allocated based on the
“coincident peak demand for the months of June, July, August, and September (4CP) . . . .”
913
      ETI Ex. 67 (Talkington Rebuttal) at 8-9.
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          Kroger witness Higgins also disputed the use of A&E 4CP for allocation of transmission
costs for the same reasons noted above concerning production cost allocation. Moreover, he
compared the different allocation factors—specifically, ETI’s proposed A&E 4CP, the A&E, and
Mr. Benedict’s recommended A&P. His calculations indicated that A&E 4CP and the A&E produce
similar results, while A&P radically departs from ETI’s proposed allocations.914


          The ALJs do not find sufficient or persuasive evidence to change ETI’s proposed
methodology for allocation of transmission costs. A&E 4CP is a well-accepted method for
allocating such costs, which the Commission has repeatedly adopted. The ALJs recommend the use
of the A&E 4CP to allocate ETI’s transmission costs.


C.        Revenue Allocation

          Wal-Mart, Kroger, TIEC, and Commission Staff advocate that the rates be set on the basis of
the utility’s costs of service. These parties recommends the adoption of ETIs proposed base rate
revenue allocation, recovering from each class 100 percent of it respective Test-Year base rate costs
per the revenue requirement ultimately adopted.


          TIEC witness Pollock testified that revenue allocation is the process of determining how any
base revenue change approved by the Commission should be spread to each customer class served
by the utility. ETI proposed an overall increase in non-fuel revenues of 17.53 percent, but the
increase is not spread proportionally to all the classes.915 Rather, ETI proposed class revenue
requirements that are closely aligned with the Company’s proposed cost of service. Set out below is
the impact of ETI’s proposed base rate increase for each class:916


                       Class                                 Change in Base Revenues
                       Residential                               25.10%



914
      Kroger Ex. 2 (Higgins Cross Rebuttal) at 5-6.
915
      ETI’s revenue requirement does not include the costs associated with its requested REC Rider.
916
      See Kroger Ex. 1 (Higgins Direct) at 5-6; see also Cities Ex. 6 (Nalepa Direct) at 34.
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PUC DOCKET NO. 39896


                      Small General Service                  1.82%
                      General Service                        5.54%
                      Large General Service                  19.06%
                      Large Industrial Power Service         11.17%
                      Lighting Service                       29.36%
                      System Average                         17.53%


          The contested issue concerns whether rates should be set at cost, and any approved change in
base rate revenues should reflect the actual cost of providing service, or whether any rate increase
should be phased in for certain classes (notably Residential and Lighting classes) to reduce the
impact (rate shock)


          1. Argument for Moving Rates to Cost

          ETI and the parties in support of ETI’s class revenue allocation contend it is appropriate to
set rates at each class’ cost of service as ETI has proposed in order to avoid continuing inappropriate
and inequitable cost shifting between customer classes. TIEC witness Mr. Pollock testified that
cost-based rates send the proper price signals to customers. He noted other reasons for using cost-
of-service principles: equity, engineering efficiency (cost-minimization), stability, and conservation.
If rates are not based on cost, then some customers subsidize part of the cost of providing service to
other customers. Moreover, he suggested that by providing balanced price signals, cost-based rates
encourage conservation and may prevent waste or inefficient use. If rates are not based on a class
cost-of-service study, then consumption choices can be distorted.917


          Mr. Pollock developed a class revenue allocation based on his proposed jurisdictional and
class cost-of-service studies. If these recommendations are adopted, his class revenue allocation
produced the following results:




917
      TIEC Ex. 1 (Pollock Direct) at 63-65.
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        Rate Class             Present Non-Fuel          Proposed Base
                                   Revenues             Revenue Increases
          Service                                                              Percent Increase
Residential                           $379,382,000             $80,390,000                    21.2%
Small General                           $26,430,000               $283,000                     1.1%
General                               $159,768,000              $9,797,000                     6.1%
Large General                           $49,380,000             $8,714,000                    17.6%
Large Indus. Power                    $104,308,000              $9,862,000                     9.5%
Lighting                                $10,813,000             $2,143,000                    19.8%
Total                                 $730,080,000            $111,189,000                    15.2%

          As discussed below, Mr. Pollock also recommended lower rates for Schedules SMS and
AFC, which would reduce ETI’s revenues by about $2 million. To offset this loss, he testified that
revenues would need to be increased for other classes to achieve the total increase requested by ETI.
These changes would produce the following results:918


  Rate Class Service           Present Non-Fuel          Proposed Base         Percent Increase
                                   Revenues             Revenue Increases
Residential                          $379,382,000              $81,500,000                    21.5%
Small General                           $26,430,000               $340,000                     1.3%
General                               $159,768,000             $10,205,000                     6.4%
Large General                           $49,380,000             $8,860,000                    17.9%
Large Indus. Power                    $104,308,000             $10,153,000                     9.7%
Lighting                                $10,813,000             $2,160,000                    20.0%
Total                                 $730,080,000            $113,218,000                   15.5%
SMS/AFC Impacts                         $13,816,000            ($2,029,000)                  -14.7%
Total Sales                           $743,896,000             111,189,000                    14.9%




918
      Id. at 63-67 and Exs. JP-12 and JP-13.
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           If the Commission disallows other elements of ETI’s rate request, Mr. Pollock testified that
class revenue allocation should be reduced in accordance with how such disallowed costs were
allocated to each rate class.919


           Mr. Pollock’s tables provide examples of the impact on each class of customers when the
Commission makes final decisions concerning the Company’s proposed rate design and the final
revenue requirement.


           Staff witness Abbott testified that the Commission ordinarily sets rates for each customer
class to recover the costs incurred by the utility to serve that class. In this case, ETI’s proposed
revenues for all customer classes result in base revenues that are close to the cost of service allocated
costs. No single customer class’ proposed revenue requirement differs from ETI’s calculated cost to
serve that class by more than 3 percent. Staff acknowledges that certain classes face proportionally
larger rate increases to bring them closer to unity, where revenue recovery is based on actual cost of
service. However, Staff agrees with Mr. Pollock that setting each customer class at their cost of
service avoids inflating rates for some customer classes and subsidizing the usage of others. Staff
believes that recovering from each class its respective base rate cost is equitable and provides
appropriate pricing signals to facilitate the most efficient use of resources in the provision and
consumption of electricity. Staff also argues that the Commission has approved such class cost of
service allocation in recent rate cases.920


           Wal-Mart and Kroger concur with Staff and TIEC.




919
      Id. at 67.
920
    Staff cites Application of CenterPoint Electric Delivery Company, LLC for Authority to Change Rates,
Docket No. 28339, Order at FoF 175 (May 12, 2011) and Docket No. 16705, Second Order on Rehearing at
FoF 245 (Sept. 4, 1998). TIEC witness Pollock also testified that Commission precedent supports allocation
of costs based on the cost of service study. He also cited to the CenterPoint case and to Application of AEP
Texas Central for Authority to Change Rates, Docket No. 28840, Order at 50 (Aug. 15, 2005). TIEC Ex. 1
(Pollock Direct) at 65.
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          2. Argument for Gradualism

          Cities witness Karl Nalepa pointed out that, under ETI’s proposed rates, the Residential and
Lighting customer classes receive the highest rate increases while the Small General Service,
General Service, and Large Industrial Power Service classes receive below system average rate
increases of 1.62 percent, 4.81 percent, and 10.77 percent, respectively. However, he examined Test
Year customer quantities, energy and loads by customer class for each of ETI’s last three cases, and
he concluded that residential and lighting customers are not imposing an undue cost burden on the
system. Instead, other classes are growing at a faster rate, causing system costs to increase.
Moreover, Mr. Nalepa testified that a number of events are occurring with the Entergy system that
will have significant impact on costs, including: Entergy’s efforts to join MISO; plans by EAI and
EMI to leave the Entergy System Agreement; and the possible divestiture of the transmission system
by all Entergy Operating Companies. Given these uncertainties, Mr. Nalepa proposed that any rate
increase or decrease be spread proportionately across the system classes. Then, once Entergy and
ETI address the proposed system cost changes, a reasonable class cost allocation study can be
presented.921


          State Agencies do not take a position on overall class revenue allocation but request that
ETI’s proposed rate increase for the Lighting class be moderated. ETI proposes to set base rate
revenues for the Lighting class based on the class cost allocation study, without any adjustment,
which would result in a 20.38 percent increase to the Lighting class, when the entire ETI system
would receive a 15.32 percent increase. Thus, under ETI’s proposal, this class would receive a
percentage increase about 1.33 times the system average. Ms. Pevoto contended that that this
increase would be excessive and would create significant rate shock to the class. Because the
services of the Lighting class provides benefits all customers on the system, Ms. Pevoto believes it
would be reasonable to mitigate the rate shock so that lighting customers can afford to continue their
lighting service. Otherwise, she suggested, some lighting customers may reduce lighting services or




921
      Cities Ex. 6 (Nalepa Direct) at 34-37.
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refrain from ordering additional lights. This, in turn, would adversely affect the benefits that
lighting service provides to the public.922


          Ms. Pevoto also pointed out that in 2009, the Commission adopted a rate moderation
proposal for a similar rate class served by another utility. In that case, the Commission recognized
that the Lighting class was unique in the combination of the public good it performs and in its
demand characteristics.923 To mitigate the rate shock on the lighting customers in the present case,
Ms. Pevoto recommended a cap on any base rate increase that would be equal to the smaller of:
(1) the lighting class percentage rate increase resulting from the PUC-approved cost of service
allocation study, or (2) the allowed system percentage rate increase. If the percentage rate increase
is smaller than the allowed system percentage rate increase, then no mitigation adjustment would be
necessary. However, if the PUC-approved cost of service allocation results in a percentage base rate
increase for the lighting class that is greater than the allowed system percentage increase, then she
urged that a mitigation reduction should occur. She also proposed that any mitigation reduction for
the lighting class should be spread to other remaining classes, based on each class’ cost of service.924


          ETI argues that the State Agencies are proposing the continuation of a significant subsidy by
other classes. The Company notes that its allocation of costs to the Lighting class is based on the
revenue requirement developed for that class. ETI acknowledges that its proposed increase for the
Lighting class is 20.38 percent greater than the system average increase, but it is less than the
Residential class’s proposed increase of 21.64 percent. ETI witness Ms. Talkington testified that the
Company does not support any subsidies between rate classes. She testified that previous rate cases
with subsidies for the Lighting class have pushed the class farther away from cost.925


          OPC argues that cost of service should not be the sole factor in setting rates and that
gradualism should be used in appropriate circumstances. OPC witness Benedict disagreed with

922
      State Agencies Ex. 2 (Pevoto Direct) at 12-13.
923
   Application of Oncor Electric Delivery Company for Authority to Change Rates, Docket No. 35717, Order
on Rehearing at 32 (Nov. 30, 2009).
924
      State Agencies Ex. 2 (Pevoto Direct) at 15-16.
925
      ETI Ex. 67 (Talkington Rebuttal) at 18-19.
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Mr. Pollock’s (and Staff’s) citation to the CenterPoint and AEP TCC rate cases to reject the concept
of gradualism because both CenterPoint and TCC are unbundled transmission and distribution
(T&D) utilities whose charges had a small impact on retail customers’ total bill. He noted that the
number runs for TCC and CenterPoint showed retail revenue increases of only 0.14 percent and
1.30 percent, respectively, with some classes receiving rate decreases.926 Mr. Benedict cited the
following language by the Commission in its Order for the TCC case:


          The Commission declines to adopt gradualism in this case. This proceeding
          develops the T&D rates, as opposed to the broader rates developed for a fully
          integrated utility. As the T&D rates are only a subset of the total rates paid by
          customers, changes to the T&D rates would not have as large an impact as they
          would if the broader rates for a customer class were changed by the same percentage.
          . . . 927

In Mr. Benedict’s opinion, gradualism should be employed when setting rates for ETI because ETI is
an integrated utility and has proposed a large rate increase.928


          Mr. Benedict also emphasized the imprecise nature of a cost of service study. He noted that
ETI’s cost of service study had 47 allocation factors and, even at the summary level, 22 expense
categories and 24 rate base categories.929 Thus, he stated, there are a host of decisions made by the
cost of service analyst which, in combination with the various account entries, yield a class’ reported
cost of service. Mr. Benedict also pointed to disagreement among qualified experts on the “correct”
allocation for certain classes of costs.930 In addition to these allocation questions, Mr. Benedict
stated that any disallowances made to ETI’s requested costs will have asymmetric effects on class

926
   OPC Ex. 8 (Benedict Cross Rebuttal) 11-12; Ex. NAB-4, Docket No. 28840, TCC Number Run (July 21,
2005); and Ex. NAB-5, Docket No. 38339, Revised Number Running Schedules (Feb. 18, 2011).
927
      Id. citing Docket No. 28840, Order at 23 (Aug. 15, 2005).
928
      OPC Ex. 8 (Benedict Cross Rebuttal) at 9-14.
929
    Allocation factors are provided in Schedule P-7.1; Expenses are summarized in Schedule P-7.4; Rate Base
is summarized in Schedule P-7.5.
930
    He noted, for example, that his direct testimony and Mr. Nalepa’s direct testimony proposed a different
allocation methodology for production-related capacity costs, transmission costs, and certain System
Agreement costs. Mr. Pollock proposed a different allocation method for municipal franchise fees and local
gross receipts taxes. Mr. Abbott recommended different allocation methods for municipal franchise fees and
other franchise taxes.
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cost of service depending on how the costs were allocated. Thus, while the cost of service study is
an important element of ratemaking, Mr. Benedict stressed that it is not the only consideration.931


          Due to the wide variation of rate increases obtained from ETI’s cost of service study,
Mr. Benedict thought that rate moderation (gradualism) would be appropriate. However, he added,
until decisions are made regarding the cost disallowances and allocation modifications proposed by
the parties, it is unclear which rate classes should be granted rate moderation and the degree to
which rate moderation is needed. Mr. Benedict said that the system average rate increase should be
used as a benchmark for rate moderation, but not assigned uniformly to all classes as Mr. Nalepa
proposed or to just one class as Ms. Pevoto suggested. Instead, he believed it would be reasonable
to establish a floor and a ceiling for the increases in revenue from each class, such that a class’
individual percentage increase in revenue requirement is within a defined range of the system’s
average revenue increase. Therefore, Mr. Benedict recommended that any rate increase for a
particular class be restricted to a range of 0.75 to 1.25 times the system’s average increase. This
would result in rate increases up to 25 percent lower or 25 percent higher than the average rate
increase for the system as a whole. Based on a system average increase of 17.53 percent, individual
class increases would range from 13.15 percent to 21.91 percent under Mr. Benedict’s proposal.932


          3. ALJs’ Recommendation

          The parties presented persuasive argument on both sides of the issue. Clearly, in any rate
case, movement toward unity—setting rates to cost—is appropriate when such movement does not
result in rate shock to a particular class or classes. If rate shock is likely, Commission precedent
supports the use of gradualism. These policies apply to both a fully integrated utility, as well as a
T&D. The salient issue is whether the utility’s proposed increase is so out of proportion or harsh to
a particular class that some form of gradualism should be applied.           In this rate case, the
preponderance of the evidence does not support the use of gradualism, even for the Lighting class.
While that class may receive an increase almost 1.33 times the system average increase, Commission


931
      OPC Ex. 8 (Benedict Cross Rebuttal) at 14-17.
932
      OPC Ex. 8 (Benedict Cross Rebuttal) at 17-19.
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precedent indicated an appropriate ceiling of 1.5 or even 1.75 times the system average is
appropriate.933 As to applying OPC’s proposed floor and ceiling approach, this method was
introduced in cross-rebuttal with no calculations depicting the impact on each class. The ALJs do
not recommend its adoption because it fails to offer significant movement towards class
responsibility for cost of service. The ALJs do not recommend Mr. Nalepa’s suggestion to impose
any revenue change on an equal percent basis because it offers no movement towards unity.
Accordingly, the ALJs concur with the parties supporting ETI that revenue allocation in this case
should be based on each class’s cost of service and consistent with the ALJs’ recommendations in
the PFD that impact revenue allocation.


D.          Rate Design [Germane to Preliminary Order Issue Nos. 15, 18, and 20]

            Staff explained that the Commission has traditionally established class costs of service based
on the principle of cost causation. Staff believes the Commission has consistently required
substantial justification for departing from this principle when setting rates that result in
cross-subsidization between customer classes. With respect to intra-class cost causation and rate
design, Staff maintains that the considerations are somewhat different. Rather, the Commission has
traditionally given more weight to policy considerations other than cost causation in determining
intra-class rate design issues because the danger of permanent subsidies within a particular class is
relatively low.934 For instance, Staff witness Abbott testified that customer usage within a class may
vary throughout the year. He noted that a low-load-factor customer might become a high-load-factor
customer, resulting in a different mix of charges throughout the year.935 While an individual
customer’s usage characteristics might frequently change and thereby lessen the impact of cost
shifting within a class, Mr. Abbott testified that such customers were unlikely to shift to a different
customer class.936 While subsidies in the customer class allocation context might be permanent, this

933
      See Docket No. 28840, Order at 23 (rejecting ALJs’ proposed ceiling of 1.75 times the system average).
934
    Staff cites to Mr. Abbott’s cross-examination at Tr. at 1818 (“Q: And is there a distinction between factors
that you would consider such as costs or other factors when you’re discussing class allocation as opposed to
rate design issues? A: I would say there are different considerations and weights to considerations and the
analysis of allocating costs to classes versus the analysis of allocating costs to rates within a class.”).
935
      Tr. at 1818.
936
      Id.
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was not necessarily the case for intra-class rates. Moreover, these shifting usage characteristics
make it more difficult to identify cost drivers within a rate class. Staff suggests that consideration be
given to policies such as customer impact and energy efficiency.


          The ALJs agree with Staff’s analysis. Mr. Abbott recommended that the Commission apply
gradualism—limiting the magnitude of rate changes—to help stabilize customer expectations and
reduce risk.937 ETI witness Talkington also advised caution in response to suggested changes to
ETI’s proposed rate design, noting that the ultimate impact on a customer’s bill is important.938
However, the ALJs’ rate design recommendations are based on the evidence and argument for each
customer class or rate schedule. Thus, the ALJs’ recommendation on the specific rates or charges
for the industrial customers will impact all other customer classes but that impact is not known at
this time.


          1. Lighting and Traffic Signal Schedules

          Cities witness Dennis W. Goins explained ETI’s Lighting and Traffic Signal Schedules.
ETI’s principal rate schedule for street lighting customers is Schedule SHL (Street and Highway
Lighting Service), while Schedule TSS (Traffic Signal Services) is the principal rate schedule for
ETI’s traffic lighting customers that own and maintain their lighting facilities. For Schedule SHL,
the rate includes four categories of service (Rate Groups A, C, D, and E). Rate Group A includes
ETI’s standard fixture and lamps mounted on existing standard wood poles that ETI installs and
maintains. If a customer wants nonstandard lighting facilities (those not provided in Rate Group A),
the customer is assigned to Rate Group C and required to prepay ETI for the incremental cost of the
nonstandard facilities. Lighting facilities that are customer-owned and customer-maintained are
assigned to Rate Group D, while incidental lighting services (for example, underpass lighting) are
assigned to Rate Group E. Customers in Rate Groups A and C pay a fixed monthly charge per
lighting fixture, while customers in Rate Groups D and E pay a fixed (and identical) energy charge
per kWh.        Each customer’s monthly bill also includes charges for ETI’s fixed fuel factor


937
      Staff Ex. 7 (Abbott Direct) at 25-26.
938
      ETI Ex. 67 (Talkington Rebuttal) at 16.
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(Schedule FF) and applicable riders applied to monthly kWh per fixture. Under Schedule TSS,
traffic signal customers are subject to a minimum monthly charge ($3.20 proposed) per point of
delivery, plus a fixed kWh rate and all applicable rider charges.939


           Cities request that the Commission require ETI to institute a discounted lighting rate for
Light Emitting Diode (LED) installations. Mr. Goins testified that the basic structure and pricing
provisions of the SHL and TSS rates were designed for lighting fixtures that use older, less
energy-efficient bulb technology, and ETI did not conduct any analyses to estimate the cost
differential of serving street lighting and traffic signal customers that use energy-efficient LED
fixtures. In fact, Dr. Goins noted that the basic structure and pricing provisions of the SHL and TSS
rates have been place for years.940


           In Dr. Goins’ opinion, adoption of LED lighting rates would help reduce energy consumption
in Texas because such rates help offset the high front-end cost of LED lights and encourage
municipalities to adopt energy-efficient LED options. In 2010, the Commission approved a street
and traffic signal rate for El Paso Electric Company that included separate charges for LED traffic
signals.941 In that case, the fixed monthly rate for LED signals was generally less than one-third the
comparable rate for incandescent signals.


           Dr. Goins recommended that the Commission require ETI to modify monthly fixed charges
in Schedule SHL (Rate Groups A and C) and the monthly minimum charge in Schedule TSS to
reflect a 25 percent discount for LED installations. Under his proposal, the discounted Rate
Group A fixed charges (if applicable) in Schedule SHL would be applied according to the estimated
monthly kWh consumption of the installed LED fixture. In addition, he recommended reducing by
25 percent the Schedule SHL kWh charges applicable to LED customers assigned to Rate Groups D
and E to reflect the lower cost of operating and maintaining LED fixtures. And he added that, in the

939
      Cities Ex. 4 (Goins Direct) at 22-23.
940
      Id. at 23.
941
   Application of El Paso Electric Company to Change Rates, to Reconcile Fuel Costs, to Establish
Formula-Based Fuel Factors, and to Establish an Energy Efficiency Cost Recovery Factor, Docket No.
37690 (July 30, 2010).
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future, ETI should be required to provide detailed information regarding differences in the cost of
serving LED and non-LED lighting customers.942


            Dr. Goins also requested that the Commission require ETI to eliminate the service condition
applicable to Rate Groups A and C in Schedule SHL that charges a $50 fee for any replacement of a
functioning light with a lower-wattage bulb. He stated that this fee actively discourages customers
from adopting more energy-efficient lighting technologies (for example, LED devices), and was not
supported in ETI’s filing.         In Dr. Goins’ view, this barrier to conservation and efficiency
improvements should be eliminated.943


            Staff disagrees with Cities’ request that ETI institute a discounted lighting rate for LED
installations. Mr. Abbott testified that Cities did not provide empirical cost data to support this
request. Without data on which to base an LED installation discount, he recommended that the
Commission not require ETI to provide such a discount at this time. However, because of the
growing use of LED installations and the potential cost savings to be realized from these
installations, Mr. Abbott did recommend that the Commission require ETI to perform a cost study to
determine appropriate cost-based rates for LED installations. This cost study could be used to
develop LED lighting rates, which Mr. Abbott recommended ETI be required to submit as part of its
next base-rate case.944


            ETI is willing to perform a study to determine the feasibility of implementing LED lighting
rates as part of its next base rate case filing. ETI witness Talkington explained that the Company
does not currently offer ETI-owned LED lights but may do so in the future. She stated that if a
customer wishes to use LED technology, it can install LE fixtures and receive service under
Schedule SHL, Rate Groups D and E, or the existing Schedule TSS.945



942
      Cities Ex. 4 (Goins Direct) 22-26.
943
      Id.
944
      Staff Ex. 7 (Abbott Direct) at 28.
945
      ETI Ex. 67 (Talkington Rebuttal) at 17.
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          Ms. Talkington took issue with Dr. Goins’ proposed 25 percent decrease in Schedule SHL
(Rate Groups A and C) and Schedule TSS for an LED option because the 25 percent rate reduction
was not calculated. Thus, ETI prefers that it propose rates after a cost study. Ms. Talkington also
disagreed with Dr. Goins’ proposal for a 25 percent decrease in the energy-only options under
Schedule SHL, Rate Groups D and E or Schedule TSS for customer-owned lights. She believes that
a customer will have the benefit of more efficient LED lights by the reduction in energy
consumed.946


          The ALJs find persuasive Dr. Goins’ testimony that: (1) the cost of street and traffic lighting
services can be significant for many cities and towns; (2) government agencies face increasing
pressure to control budgets and energy-efficient lighting is a good option; (3) LED fixtures use
significantly less energy than incandescent and most other light options, last longer, and may require
less maintenance; and (4) LED lighting rates would encourage municipalities to adopt
energy-efficient LED options and help offset the high front-end cost of LED lights.947 However, the
ALJs concur with ETI and Staff that ETI should be directed to perform a LED lighting cost study
before extensive changes are made to its lighting rates. The ALJs further recommend that ETI
conduct this study before filing its next rate case and provide the results of any completed study to
Cities and interested parties as soon as practicable but no later than the filing of its next rate case, as
requested by Cities. Further, the ALJs recommend that the study include detailed information
regarding differences in the cost of serving LED and non-LED lighting customers, if ETI has LED
lighting customers taking service at the time it conducts its study. Finally, the ALJs note that ETI
did not dispute Dr. Goins’ suggestion to eliminate the service condition for Rate Groups A and C in
Schedule SHL that charges a $50 fee for any replacement of a functioning light with a lower-wattage
bulb. As noted by Dr. Goins, this fee discourages customers from adopting more energy-efficient
lighting (such as LED devises). The ALJs concur and recommend that ETI modify the applicable
tariffs to eliminate this fee for any replacement of a functioning light with a lower-wattage bulb.




946
      Id. at 17-18.
947
      Cities Ex. 4 (Goins Direct) at 24-25.
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          2. Demand Ratchet

          Staff witness Abbott testified that a demand ratchet is a provision in a utility’s tariff that
allows it to bill a customer based upon on the greater of either demand by that customer in the
current month, or some fixed percentage of the customer’s demand occurring during previous
months. The Commission approved a settlement in Docket No. 37744, ETI’s last base rate case, in
which, among other things, ETI agreed to eliminate all life-of-contract demand ratchets from its
tariffs for new customers with the implementation of rates. ETI further agreed that, in its next rate
case, it would eliminate the life-of-contract ratchet for existing customers.948 The Docket No. 37744
stipulation stated:


          Life-of-Contract Demand Ratchet. The Signatories agree that the life-of-contract
          demand ratchet provision in Rate Schedules Large Industrial Power Service [LIPS],
          Large Industrial Power Service-Time of Day [LIPS-TOD], General Service [GS],
          General Service-Time of Day [GS-TOD], Large General Service [LGS], and Large
          General Service-Time of Day [LGS-TOD] shall be excluded from the rate schedules
          in ETI’s next rate case. The Signatories further stipulate that the foregoing rate
          schedules will be revised so that the life-of-contract demand ratchet provision shall
          not be applicable to new customers and, for existing customers, shall not exceed the
          level in effect on August 15, 2010.949

          ETI then filed compliance tariffs in Docket No. 37744, which implemented the first part of
the settlement by excluding new customers from its proposed life-of-contract demand ratchet. The
following is the relevant sections from that compliance tariff, which is applicable to Large Industrial
Power Service (LIPS) customers (all customers taking service under this tariff are required to enter
into a service agreement contract with ETI):




948
   Staff Ex. 7 (Abbott Direct) at 16; Application of Entergy Texas, Inc., for Authority to Change Rates and
Reconcile Fuel Costs, Docket No. 37744, Order at FOF 26(f) (Dec. 13, 2010). The ratchet is applicable to the
General Service (GS), General Service – Time of Day (GS-TOD), Large General Service (LGS), Large
General Service – Time of Day (LGS-TOD), Large Industrial Power Service (LIPS), and Large Industrial
Power Service – Time of Day (LIPS-TOD).
949
      TIEC Ex. 27 (Docket No. 37744 Stipulation and Settlement Agreement) at 6.
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          VI.    DETERMINATION OF BILLING LOAD
                 The kW of Billing Load will be the greatest of the following:
          (A)    The Customer’s maximum measured 30-minute demand during any
                 30-minute interval of the current billing month, subject to §§ III, IV and V
                 above; or
          (B)    75% of Contract Power as defined in § VII; or
          (C)    (1) For existing accounts with contracts for service for loads existing
                 prior to August 15, 2010 – 60% of the Highest Contract Power
                 established prior to August 15, 2010 as defined in § VII, (2) For new
                 accounts with contracts for service for loads not existing prior to
                 August 15, 2010 – Does Not Apply; or
          (D)    2,500 kW.

          VII.   DETERMINATION OF CONTRACT POWER
                 Unless Company gives Customer written notice to the contrary, Contract
                 Power will be as defined below:

                 Highest Contract Power – the greater of (i) the highest Billing Load
                 established under the currently effective contract, or (ii) the kW
                 specified in the currently effective contract.

                 Contract Power- the highest load established under § VI (A) above during the
                 12 months ending with the current month. For the initial 12 months of
                 Customer’s service under the currently effective contract, the Contract Power
                 shall be the kW specified in the currently effective contract unless exceeded
                 in any month during the initial 12-month period.950

          In this case, ETI changed the tariff provisions for all customers:


          VI.    DETERMINATION OF BILLING LOAD
                 The kW of Billing Load will be the greatest of the following:
          (A)    The Customer’s maximum measured 30-minute demand during any
                 30-minute interval of the current billing month, subject to §§ III, IV and V
                 above; or
          (B)    75% of Contract Power as defined in § VII; or
          (C)    2,500 kW; or
          (D)    60% of the kW specified in the currently effective contract.

          VII.   DETERMINATION OF CONTRACT POWER
                 Unless Company gives Customer written notice to the contrary, Contract
                 Power will be as defined below:


950
      TIEC Ex. 29 (Tariff Approved in Docket No. 37744)(emphasis added).
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                  Contract Power shall be the highest load established under § VI(A) above
                  during the 12 months ending with the current month. For the initial 12
                  months of Customer’s service under the currently effective contract, Contract
                  Power shall be the kW specified in the currently effective contract unless
                  exceeded in any month during the initial 12-month period.951

          The contested issue concerns ETI’s new language. ETI maintains the new language is not a
life-of-contract ratchet. Commission Staff, TIEC, and DOE disagree. Stated simply, Department of
Energy (DOE) witness Dwight D. Etheridge testified that the introduction of the term “kW specified
in the currently effective contract” transforms what was a 12-month ratchet into a life-of-contract
ratchet.952


          At the outset, the ALJs note that some of ETI’s proposed tariffs do comply with the
stipulation in the prior case. ETI eliminated the life-of-contract provisions for the GS and GS-ToD
customer classes. However, ETI’s new language for the remaining ratchet classes, according to
Staff witness Mr. Abbott, has the effect of maintaining a slightly different type of life-of-contract
demand ratchet.953 The discussion in this section applies to the LIPS class but the same argument
follows for LGS and GS classes.


          The parties contesting ETI’s demand ratchet language argue that: (1) ETI’s compliance tariff
in Docket No. 37744 was consistent with the parties’ agreement; (2) ETI’s proposal imposes a life-
of-contract demand ratchet; (3) the service agreement and tariff are linked; and (4) the new demand
ratchet is not equitable or cost-based. These arguments are set out below.




951
    ETI 67 (Talkington Direct) at Ex. MLT-R-4 at 15 (emphasis added). ETI changed the relevant language
in its tariff in its rebuttal testimony. Thus, the testimony of Messrs. Etheridge and Abbott can be slightly
confusing because these witnesses address the tariff initially proposed by ETI.
952
      DOE Ex. 1 (Etheridge Direct) at 11.
953
      Staff Ex. 7 (Abbott Direct) at 16-19.
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               ¾ The agreed tariff from Docket No. 37744 was consistent with the parties’
                 agreement and shows how LIPS billing load should be calculated.

          Staff, TIEC, and DOE agree that when ETI filed the compliance tariff in Docket No. 37744,
the only demand ratchet that remained in the LIPS tariff for ETI’s new customers was a 12-month
demand ratchet. ETI removed the life-of-contract ratchet that set a perpetual obligation for a
customer to pay for power based on its highest contract power or a percentage of its contract power.
Staff, DOE, and TIEC argue that ETI’s action in removing those provisions was consistent with the
agreement and is evidence of what ETI should have done in this case. They contend that ETI
witness Ms. Talkington agreed that the settlement eliminated both the highest load established under
the currently effective contract and the amount specified in the contract.954 In other words, the
compliance tariff tracked the agreement.


          ETI does not directly respond to this argument: Ms. Talkington did not address this in her
rebuttal testimony. However, ETI states that the ALJs should “not be distracted by ETI’s initial
error of unintentionally removing the contracted capacity provision as to new customers in its
compliance tariffs in Docket No. 37744.”955 Apparently, ETI believes that the tariffs it filed in
compliance with the Docket No. 37744 agreement were in error.


               ¾ ETI proposes a demand ratchet in this case that is based on the contracted quantity
                 stated in the tariff-required service agreement.

          All parties agree that what ETI proposes in this docket is different from the Docket
No. 37744 tariff, as evidenced by Ms. Talkington:


          Q:         So last time, when the company and the parties implemented the elimination
                     of the life-of-contract ratchet, it eliminated the 60 percent ratchet applicable
                     to both actual demand during the contract period or the contract – the amount
                     specified in the contract.
          A.         Yes, the way it’s put in the schedule, yes.
          Q:         And that’s different than what you proposed in this case?

954
      Tr. at 1432.
955
      ETI Reply Brief at 91.
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          A:         It is.
          Q:         And do you apply a different meaning to the agreement of what the life of
                     contract ratchet meant than was applied in the tariff?
          A:         Yes. What we have in this case is that the life-of-contract power relates to
                     the highest load established under the currently effective contract . . . 956


          According to ETI, its proposed language does not impose life-of-contract ratchet, as defined
by Mr. Pollock in Docket No. 37744 or by Messrs. Etheridge and Abbot in this case.


      Witness                                                  Definition
      Pollock                 “A life-of-contract ratchet is based on the highest demand ever imposed
                              by a customer during the term of the contract.” He further explained
                              that ETI’s proposed Docket No. 37744 tariff had “a life-of-contract
                              ratchet [which] imposes a perpetual obligation to pay a minimum
                              demand charge throughout the term of the contract.”957
      Etheridge               “A life-of-contract ratchet is a ratchet where you’re not looking solely at
                              current loads but some other loads in some prior period, so it creates a
                              perpetual obligation to pay.”958
      Abbott                  “[A] life of contract demand ratchet, which is based upon the highest
                              demand established in the time period. . . . is one type of life-of-contact
                              demand ratchet”959

ETI argues that the above definitions all make reference to the demand actually imposed by the
operations of the customer’s physical plant. But the contracted quantity provision it proposes is a
minimum kW amount contractually agreed between the two parties to the service agreement, which
is a required contract between the customer and ETI.960 ETI argues the provision is not set by actual
events during the term of the contract or in a prior period of the term of the contract, or in a monthly
or 30-minute time period within the term of the contract; rather, it is set in the contract:



956
      Tr. at 1432-1433 (emphasis added).
957
      DOE Ex. 3 (Docket No. 37744 testimony excerpt) at 5-6.
958
      Tr. at 2004.
959
      Tr. at 1817.
960
   Mr. Etheridge testified that customers taking service under Schedule LIPS must sign a contract for service.
Tr. at 1991.
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          That contracted quantity is set as, to use Mr. Etheridge’s words, “an estimate” that
          cannot be unilaterally changed by the Company; instead, a change to that kW amount
          could only be made through negotiation between the two parties or through a
          proceeding before the Commission. To use Mr. Pollock’s definition, it is not a
          demand “imposed by the customer during the term of the contract.” It is instead a
          fixed, contractually agreed to amount that is set as a condition of service prior to the
          contract term.961

          In sum, ETI argues the provision in question are not life-of-contract ratchets that lock the
customer into the highest demand ever imposed by the customer’s actual load during the term of the
contract. Rather, they are, at most, 12-month ratchets that set the billing demand over a 12-month
period, but not the life of the contract, at 75 percent.


          Staff suggests that the Commission does not, fortunately, have to determine what contract
provision may or may not constitute a life-of-contract demand ratchet. Rather, the Commission must
ensure that ETI fulfilled its obligations under the Docket No. 37744 settlement. Staff believes that
the parties to that settlement understood the meaning of the life-of-contract term, ETI followed
through with compliance tariffs that evidenced its understanding, and now ETI should be required to
stick with its agreement.


              ¾ The service agreement and tariff are linked.

          According to TIEC, ETI tries to make the argument that its proposal is justified because ETI
and its large customers may sign an agreement for service that specifies a customer’s contract
power. This does not justify ETI’s proposal because ETI’s form “Agreement for Electric Service”
expressly states that the agreement is subject to the terms of “applicable rate schedules.”962 Thus,
maintains TIEC, the LIPS tariff billing load provisions impact a customer’s contract power and can
reasonably reduce a customer’s billing load below its contract power if the customer has a reduction
in load lasting longer than 12 months.




961
      ETI Initial Brief at 211 (footnotes omitted), citing Tr. at 1994, 2012.
962
      ETI Ex. 3, Schedule Q 8.8 at 11.1.
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          ETI’s proposal should be rejected, argues TIEC, because it would allow the utility to
indefinitely seek revenue from a customer that has nothing to do with the customer’s actual usage or
the utility’s costs. For example, if a plant took 150 MW of load in its heyday, under ETI’s proposal,
the plant would be obligated to pay demand charges based on 60 percent of its original contract
power. This is because ETI’s standard agreement requires the utility’s “express approval” to set a
new contract power and the utility therefore could choose not to negotiate (or negotiate in a timely
manner) a new contract power.963 If LIPS billing load is tied to contract power, then its customers
would be completely at its mercy to negotiate a reasonable contract power based on the customer’s
actual usage for the time period. TIEC contends this is a ridiculous result and would render the
parties’ agreement to eliminate the life-of-contract ratchet meaningless.


              ¾ ETI’s new demand ratchet is not equitable or cost-based.

          TIEC does not dispute that a 12-month ratchet is reasonable. However, Mr. Pollock, in
Docket No. 37744, explained why a perpetual obligation to pay demand costs for load that the utility
does not serve is objectionable:


          While it is appropriate to require customers to pay for the facilities they use, a
          perpetual obligation is both extreme and unnecessary. Typical demand ratchets
          reach back twelve months. A life-of-contract ratchet can reach back decades. This is
          particularly inappropriate when longstanding customers have permanently reduced
          operations. A customer that has reduced operations is not purchasing the same level
          of generation and transmission services as in the past, nor is ETI procuring the same
          level of generation and transmission services for the customer. Further, because of
          load growth on the ETI system, the capacity no longer being used by the customer
          would be used by other customers. Thus, a life-of-contract ratchet does not properly
          reflect cost-causation.964

              ¾ Witness Recommendations.

          Staff witness Mr. Abbott recommended that ETI be required to eliminate from its LGS,
LGS-ToD, LIPS, and LIP-ToD tariffs the language that results in a ratchet based upon the current


963
      ETI Ex. 3, Schedule Q 8.8 at 11.2.
964
      DOE Ex. 3.
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effective contract-specific demand.           Also, if the Commission approves Mr. Abbott’s
recommendation, he stated that the billing determinants used to calculate the rates for the affected
customer classes will likely change. Therefore, ETI should be required to update the affected billing
determinants and reflect the resulting change in its rates in the compliance filing of this docket.965


          DOE witness Etheridge also recommends that same for the LIPS tariff. He specified
language that will exclude the life-of-contract ratchet language and retain the existing rolling
12-month ratchet language in Schedule LIPS.966 Specifically, he proposed the following:


          VI.      DETERMINATION OF BILLING LOAD
                   The kW of Billing Load will be the greatest of the following:

          (A)      The Customer’s maximum measured 30-minute demand during any
                   30-minute interval of the current billing month, subject to §§ III, IV and V
                   above; or
          (B)      [60%] of Contract Power as defined in § VII; or
          (C)      2,500 kW.

          VII.     DETERMINATION OF CONTRACT POWER
                   Unless Company gives Customer written notice to the contrary, Contract
                   Power will be as defined below:

                   Contract Power- the highest load established under § VI (A) above during the
                   12 months ending with the current month. For the initial 12 months of
                   Customer’s service under the currently effective contract, the Contract Power
                   shall be the kW specified in the currently effective contract unless exceeded
                   in any month during the initial 12-month period.

                ¾ ALJs Recommendation.

          The ALJs find that ETI violated its agreement with the signatories in Docket No. 37744: the
tariff language proposed by ETI is a life-of-contract demand ratchet. ETI failed to explain how the
compliance tariffs adopted in Docket No. 37744 were in error. ETI’s argument that its new
language is not a life-of-contract demand ratchet was unpersuasive. To justify its modification, ETI


965
      Staff Ex. 7 (Abbott Direct) at 20.
966
      ETI can adopt similar language for its LGS, LGS-ToD, LIPS, and LIP-ToD tariffs.
SOAH DOCKET NO. XXX-XX-XXXX                   PROPOSAL FOR DECISION                         PAGE 295
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relied only on a portion of Mr. Pollock’s Docket No. 37744 definition.              Moreover, both
Messrs. Abbott and Etheridge were unequivocal that ETI, contrary to its agreement in the previous
rate case, is imposing a life-of-contract or perpetual obligation to pay. Finally, the weight of the
evidence supports a finding that the demand ratchet ETI proposes in this case is not equitable or cost
based. The ALJs recommend that ETI’s proposed LIPS tariff be amended to include the language
proposed by Mr. Etheridge. The ALJs concur with Mr. Etheridge that, with such language, ETI has
a financial incentive to negotiate the maximum possible contracted level of capacity, not the
minimum, and the result is consistent with the Docket No. 37744 agreement.


          3. Large Industrial Power Service (LIPS)

          TIEC witness Pollock explained that Schedule LIPS recovers base rates through a seasonally
adjusted demand charge (per kW) and a two-step non-fuel energy charge (per kWh). The demand
charges are also adjusted (either up or down) to reflect the differences in costs by delivery voltage.
ETI’s existing LIPS schedule has no customer charge. In its initial filing, ETI removed all
purchased power capacity costs from base rates and proposed recovering them through a PPR as a
demand charge. When it did so, the proposed demand charges were increased, but the proposed
non-fuel energy charges were substantially reduced. Following the Supplemental Preliminary Order,
which removed the PPR from further consideration, ETI proposed to roll these costs back into base
rates. The resulting rebundled demand and energy charges would increase by about the same
percentage.967


          Mr. Pollock testified that the proposed structure of Schedule LIPS does not track costs as
derived in ETI’s class cost-of-service study. Specifically, he complained: (1) there is no customer
charge, despite the fact that the customer costs allocated to the LIPS class would translate into a
monthly rate of over $6,000, and (2) the proposed non-fuel energy charges would recover a
significant amount of demand related costs. According to Mr. Pollock, production/transmission
demand-related costs are $8.47 per kW, and distribution costs add another $0.99 per kW, for a total
of $9.46 per kW. The proposed LIPS demand charges are $7.07 per kW for transmission delivery


967
      TIEC Ex. 1 (Pollock Direct) at 68-69.
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and an additional $1.82 for distribution service, for a total of $8.89 per kW. Thus, in Mr. Pollock’s
opinion, the proposed demand charges (given ETI’s requested rate increase) are too low. By
contrast, he noted, non-fuel energy costs are about 0.226¢ per kWh, while the proposed non-fuel
energy charges would average over 0.600¢. Thus, these charges are 2.5 times higher than the
non-fuel energy costs based on ETI’s filing.968


                       (a) A New Customer Charge

           TIEC urged that any increase in Schedule LIPS should be used to create a customer charge.
Mr. Pollock calculated that a cost-based customer charge should be about $6,050 per month, and he
recommended an initial customer charge of $6,000 per month. This would collect approximately
$5.9 million ($6,000 x 984 bills). He added that any remaining increase not accounted for by the
initial customer charge should be collected in the demand charges. He also stated that the non-fuel
energy charges should not be changed unless the LIPS class is allocated less than a $5.9 million
increase. In that event, he recommended that the non-fuel energy charges should be decreased. This
would gradually correct the imbalance between the below-cost demand charges and above-cost
energy charges. Mr. Pollock further stated that the delivery voltage adjustment applicable to
distribution service should be retained so that the rate better reflects the cost. Should the LIPS class
not receive an increase or if base rates are decreased, Mr. Pollock recommended that the customer
charge should be reduced proportionally. Any remaining revenue surplus should be applied to
reduce the non-fuel energy charges to cost and then to reduce the demand charges.969


           Staff witness Abbott also recommends the introduction of a customer charge, but a much
smaller one than that recommended by Mr. Pollock – $630.970


           DOE supports Staff’s proposed $630 customer charge. DOE witness Etheridge testified that
TIEC’s proposed $6,000 customer charge far exceeds a reasonable initial customer charge for
Schedule LIPS. For example, the existing Commission-approved monthly customer charge for

968
      TIEC Ex. 1 (Pollock Direct) at 69-70.
969
      Id. at 70.
970
      Staff Ex. 7 (Abbott Direct) at 27.
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Schedule LGS is $425.05. Mr. Etheridge stated that the introduction of a $6,000 customer charge
will lead to large shifts in intra-class revenue responsibility from high load factor customers to low
load factor customers because a customer charge does not vary with usage. He noted, as an
example, that TIEC’s proposal would increase DOE’s Big Hill annual costs by $72,000 or nearly
10 percent. Moreover, Mr. Etheridge pointed out that two parties are proposing to lower the
Schedule LGS customer charge—approving either of these recommendations and TIEC’s would
levy Schedule LIPS customers with a new customer charge that is over 23 times the level of the LGS
class. He believes such inconsistencies are inexplicable. Additionally, such disparity would present
a challenge to any customer migrating from the LGS to the LIPS class.971


          DOE witness Etheridge agreed that is appropriate to move toward cost-based rates, however,
he indicated that gradualism should be properly applied to move rates toward cost without undue
impact on low usage and low load factor customers in the LIPS class. If a new customer charge for
the LIPS class is to be imposed—it should be that recommended by Commission Staff.972


          The ALJs are persuaded by Mr. Etheridge’s testimony that the adoption of a $6,000 customer
charge far exceeds ETI’s existing customer charge in the LGS Schedule and results in a significant
and inappropriate impact to low load factor customers. Rather, Mr. Abbott’s proposed customer
charge of $630 is an appropriate charge to this customer class, particularly as ETI’s current rates
applicable to LIPS customers do not include any customer charge.973


                       (b)         Demand and Energy Charges

          In an effort to move more towards cost-based rates, Mr. Abbott recommends a slight
decrease in the LIPS energy charges and an increase in the demand charges from current rates.974
Mr. Pollock does not recommend an increase in energy charges. However, he recommends
increasing demand charges to cover any remaining revenue increase for the LIPS class that is not

971
      DOE Ex. 2 (Etheridge Cross-Rebuttal) at 3-4.
972
      DOE Ex. 2 (Etheridge Cross-Rebuttal) at 5.
973
      TIEC Ex. 1 (Pollock Direct) at 70.
974
      Staff Ex. 7 (Abbott Direct) at 27.
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accounted for with the customer charge. He suggested that such a change will gradually correct the
imbalance between the below-cost demand charges and above-cost energy charges.975


          DOE witness Etheridge expressed concerns with both proposals.               He stated that
Schedule LIPS customers are, on average, substantially more energy intensive than customers taking
service under Schedule LIPS-TOD customers. He indicated that TIEC’s proposed rate design (with
the $6,000 customer charge) would double the cost increase associated with base rates and the fuel
factor for LIPS-TOD customers compared with the average cost increase for the class as a whole.
Customers with lower load factors than Schedule LIPS-TOD customers would fare even worse.976


          Mr. Etheridge also was concerned about Staff’s proposed charges, noting that Mr. Abbott
failed to explain how the slight decrease in the LIPS energy charge and the large increase in the
demand charge would affect customers with changes in the revenue requirement ultimately assigned
to the class. Mr. Etheridge stated that even Staff’s proposed changes will noticeably shift intra-class
cost responsibility toward Schedule LIPS customers with relatively low load factors. To address his
concern that changes in the revenue requirement may have a significant impact even with Staff’s
gradual movement in rates, Mr. Etheridge recommended that Staff’s proposal should set the limit on
intra-class cost responsibility shifts.977


          The ALJs find evidentiary support for and recommend the adoption of Mr. Abbott’s
proposed changes to Schedule LIPS. There is sufficient evidence, based on Mr. Pollock’s testimony,
that Mr. Abbott’s suggested changes gradually move the rates towards cost without the risk of rate
shock. TIEC’s demand and energy proposals result in unreasonable large shifts in intra-class revenue
responsibility. However, the ALJs also agree with Mr. Etheridge that Staff’s proposal may need to
be adjusted depending on the ultimate revenue requirement adopted.




975
      TIEC Ex. 1 (Pollock Direct) at 70.
976
      DOE Ex. 2 (Etheridge Cross-Rebuttal) at 5.
977
      DOE Ex. 2 (Etheridge Cross-Rebuttal) at 5.
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          4. Schedulable Intermittent Pumping Service (SIPS)

          DOE proposes that a new rider, Schedulable Intermittent Pumping Service (SIPS), be
included in the LIPS tariff. This will allow DOE and other customers with intermittent pumping
loads to avoid application of a demand ratchet to schedulable, temporary, increased demand during
off-peak months when ETI’s costs are lowest. DOE suggests that the proposed rider will allow the
DOE to schedule important testing and oil exchanges, when possible, during off-peak months, is
consistent with existing riders, and does not adversely impact other customers.


          DOE explained that its Strategic Petroleum Reserve (Reserve) Texas sites—Big Hill in
Jefferson County and Bryan Mound in Brazoria County—play an important role in ensuring the
energy security of the United States. With a crude oil inventory of about 726.5 million barrels in
2010, the Reserve is the largest emergency supply of oil in the world. The Reserve was established
by Congress as a result of the oil supply disruption in the early 1970s.978


          DOE witness Etheridge testified that DOE takes service to its Big Hill site under
Schedule LIPS at an annual cost of approximately $770,000. Mr. Etheridge explained that the
Reserve’s sites typically operate in standby mode, with routine cyclical tests of pumping equipment.
The largest of these tests is performed every other year. These cyclical equipment tests can be
coordinated with ETI so that they occur during low peak periods.979


          On rare occasions, the Reserve can also be tapped. In its nearly 35 years of operations, there
have been three Presidential-ordered drawdowns: January 1991, the beginning of Desert Storm;
September 2005, Hurricane Katrina; and July-August 2011, the International Energy Agency
coordinated release. The latter was the largest of the three drawdowns at 30.6 million barrels.
Additionally, the Reserve has provided support to the oil industry in localized emergency or
operational situations involving a disruption in supply, such as ship channel closures and hurricanes.




978
      DOE Ex. 1 (Etheridge Direct) at 3.
979
      DOE Ex. 1 (Etheridge Direct) at 3-4
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When oil is exchanged during these situations, the Reserve will operate pumps at higher levels than
would occur during normal standby operations.980


          Mr. Etheridge proposed a rider to Schedule LIPS where maximum demands during pre-
scheduled, non-summer month operations of a limited duration are not subject to demand ratchets.
For this new rider, he proposed that the non-summer months be classified as October through May to
give customers and ETI more flexibility. (Under Schedule LIPS, non-summer months are November
through April.) Key provisions of the proposed SIPS rider include:


          ¾           A requirement that customers schedule with ETI limited duration
                      operations during non-summer months four weeks in advance.

          ¾           ETI must approve scheduled operations.

          ¾           Operations would not be allowed to exceed 10,000 kW in magnitude nor
                      last for more than 80 hours per year.

          ¾           ETI could cancel operations at any time if a capacity constraint develops.
                       If a customer failed to comply, the customer would incur costs
                      associated with ETI’s ratchet.

          ¾           A customer in compliance would not be subject to ETI’s demand ratchets
                      for loads established during those operations, but would pay the demand
                      charge in the month in which the operations occur.981

          Mr. Etheridge gave an example of charges under Schedule LIPS versus charges if the rider
were adopted. In September 2010, Big Hill conducted a test and established a maximum measured
demand of 11,640 kW, well above the site’s average maximum demand of approximately 3,000 kW.
DOE paid demand charges on the 11,640 kW in September 2010. In October 2010, ETI billed DOE
for 75 percent of that level of demand or 8,730 kW based on the rolling 12-month ratchet. Its actual
demand was 2,520 kW. In terms of actual costs, DOE paid $683,000 for its September usage. Under
the 75 percent ratchet, DOE would pay $609,000 per month. Mr. Etheridge estimated that the


980
      DOE Ex. 1 (Etheridge Direct) at 3-4.
981
      DOE Ex. 1 (Etheridge Direct) at 18.
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charges amounted to $59/kW per year, which could easily represent nearly one-half of the annual
carrying cost of a combustion turbine. Whereas, under the proposed rider, if DOE conducted the test
in February as it intended to, it would have paid ETI for the 11,640 kW level of demand, but the
usage would not be used in conjunction with ETI’s ratchets. Mr. Etheridge concluded ETI’s tariff is
not equitable. At the hearing, Mr. Etheridge estimated that the rider’s impact on other customer
classes at approximately $500,000, where Schedule LIPS base rate revenues are approximately
$110 million.982


          According to DOE, for 15 years, June 1996-June 2011, ETI, by contract, accommodated the
Reserve’s intermittent load by allowing the DOE to, once annually, “reset” the demand level to be
used by ETI when applying demand ratchets. The DOE was able to avoid significant demand
charges when typical demand was very low. After June 2011, ETI declined to apply the terms of the
long-time contract and allow the reset. DOE concedes that cost-based rates to reflect the Reserve’s
unique operations should ultimately be addressed by contract and/or new tariffs.


          DOE notes that the very purpose of some riders is to address specific customer
characteristics. For instance, Standby and Maintenance Service is available only to those customers
that co-generate electricity; the Optional Rider to Schedule LIPS for Pipeline Pumping Service alters
the designation of on peak-hours only for customers with pipeline pumping stations. Other riders,
claims DOE, seek a win-win for all customers. For instance, the Rider to LIPS for Planned
Maintenance rewards customers for scheduling routine maintenance and idling facilities during
ETI’s peak summer months of June through September by waiving the demand ratchet. DOE argues
that the proposed SIPS rider mirrors Planned Maintenance by waiving the demand ratchet if
customers are able to schedule intermittent loads outside of ETI’s peak summer months. Moving
toward cost-based rates is not discriminatory, claims DOE. Nor is rewarding customers who use
their load scheduling flexibility for the benefit of all customers.


          DOE’s proposed SIPS rider is opposed by ETI, TIEC, and Staff.



982
      DOE Ex. 1 (Etheridge Direct) at 19-20; Tr. at 2034.
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          ETI witness Talkington testified that the actual Reserve load, as Mr. Etheridge described,
does not appear to match the parameters of his proposed SIPS rider. As recently as July and August
2011, the Reserve sites had significant load requirements in order to pump vast quantities of oil. She
further testified that the Reserve loads are random in occurrence and are significant. ETI must at all
times maintain generation resources to meet this significant and randomly occurring load. In
addition, the Company has invested in transmission and other facilities to serve this customer even if
there is no or very little consumption. She believed it would not be appropriate or equitable to other
customers to remove or forgive the 12-month ratchet provision after the Company made these
investments to serve the Reserve and while the Company has maintained generation to meet its load.
If the 12-month ratchet were forgiven, then the costs incurred to serve DOE would have to be borne
by other customers in the LIPS rate class.983


          TIEC witness Pollock complained that Mr. Ethridge failed to analyze the impact on other
LIPS customers. Mr. Pollock contended the rider would discriminate against both Schedule LIPS
customers (by redefining the summer billing period) and Schedule SMS customers (whose ability to
schedule maintenance power could be subordinate to LIPS customer taking advantage of the new
Rider).984


          Staff is concerned that the rider’s unusual eligibility requirements—that a customer must
schedule load four weeks in advance, limit the high load occurrence to “off-peak months” (which is
redefined in the rider), and limit the yearly hours of load—indicate it is tailored solely to meet the
unique needs of the Reserve. According to Staff, DOE conceded that, although other customers with
intermittent loads might take advantage of the proposed SIPS rider, Mr. Etheridge was not aware of
any other actual customer that could do so.985 Staff argues the rider appears to offer unreasonably
preferential treatment to the DOE and should be rejected.



983
      ETI Ex. 67 (Talkington Rebuttal) at 41.
984
      TIEC Ex. 3 (Pollock Cross Rebuttal) at 9-10, 44-46.
985
    Tr. at 2008 (“Q: Now, who else would take advantage of this SIPS rate schedule, other than DOE? A: It’s
written such that any other customer that would have an intermittent schedulable load could take advantage of
it. But I’m not sure if there are other customers on Entergy’s system that could take advantage of it. Q: So
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        Beyond issues of discrimination, Staff is also concerned that the rider would shift costs from
the DOE to other LIPS customers. Although DOE indicates that any shift would have a small
overall impact on the LIPS class, Staff argues that the Commission should not endorse any
discriminatory rate rider.


        Although Staff and TIEC claim the proposed rider is discriminatory, other riders applicable
to Schedule LIPS customers are available at different times of the year as well (Planned
Maintenance is available only during the months of June through September) and others are limited
to customer-specific needs—such as PPS for pipeline customers. Mr. Etheridge testified that this
rider could apply to any customer—it is not restricted solely to the DOE. The ALJs do not find this
rider to be unreasonably discriminatory. As to ETI’s concern on this issue, it was focused on
whether the DOE’s load met the proposed rider’s requirements. However, if a customer taking
service under the rider is unable to schedule its maintenance and oil exchanges with ETI, then the
usage would be under the SIPS Schedule and the SIPS tariffed demand ratchet would apply.
Moreover, Mr. Etheridge testified that the impact on other customer classes is limited. As to ETI’s
cost recovery, the LIPS rider customers will pay a demand charge to cover the costs they impose on
the system in the month SIPS service is taken. The ALJs agree with DOE that the SIPS rider is
reasonable and should be adopted.


        5. Standby Maintenance Service (SMS)

        TIEC witness Pollock explained that Schedule SMS applies to customers that use
self-generation to supply a portion of their electricity requirements. These customers contract with
ETI for either standby and/or maintenance power service to replace capacity or energy normally
generated by the customer’s on-site generation. Standby (or backup) power is electric energy or
capacity supplied to replace energy or capacity that is unavailable due to an unscheduled or forced
outage of the facility. Thus, backup power must be available at any time. Maintenance power is
electric energy or capacity supplied during a scheduled outage. Unlike backup power, maintenance
power must be arranged with 24-hour notice and only during such times and at such locations that,


you don’t know that there are others who could use it. This could apply just to DOE? A: It could.”).
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in ETI’s opinion, will not result in adversely affecting or jeopardizing firm service to other
customers, prior commitments, or commitments to other utilities. In addition, the customer must
make arrangements and schedule maintenance power in writing in advance and confirmed in writing
by ETI. ETI can also limit requests for maintenance power and allocate and schedule available
service, if requests are made from more than one customer. Thus, Mr. Pollock stated that
maintenance power is of a lower quality of service than backup or standby power. He also indicated
that, because the Company can limit the amount of maintenance power, it is more likely that
customers would prefer to schedule maintenance power during the non-summer months.986


          ETI witness Talkington explained that standby service includes both the readiness to serve
and the actual delivery of power and energy delivered when a customer requires service due to a
forced outage or a planned maintenance period.           She indicated that many utilities offer a
combination of pricing and terms for demand and energy service as well as a form of reservation
charge dealing with the readiness to serve. She further indicated that the actual rate design may
differ, but standby tariffs usually contain provisions for back-up (forced outage) or maintenance
(planned outage). She concluded that ETI’s current rate schedule provides for these features, and
ETI is not proposing to change Schedule SMS in this proceeding.987


          TIEC proposes to redesign SMS service to better reflect the cost characteristics of standby
and maintenance power customers. Mr. Pollock provided his analysis to support TIEC’s position.
Under the current Schedule SMS, customers pay a monthly demand (or billing load) charge of
$1.12 per kW for backup power. The corresponding charges for maintenance power are $1.12 per
kW for outages during the summer months (May through October) and $0.84 per kW for outages
during the non-summer months. Thus, the non-summer month charge is 75 percent of the summer
month charge. Energy is priced under an array of time-differentiated charges, as shown in the table
below:988



986
      TIEC Ex. 1 (Pollock Direct) at 70-71.
987
      ETI Ex. 67 (Talkington Rebuttal) at 19-20.
988
      TIEC Ex. 1 (Pollock Direct) at 72-73.
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                           Current Schedule SMS Non-Fuel Energy Charges
                                             (¢ per kWh)
                                                          On-
                              Delivery Voltage                    Off-Peak
                                                         Peak989
                       Distribution (less than 69KV)        3.386¢      0.514¢
                       Transmission (69KV and
                       greater)                             2.334¢      0.211¢

          Mr. Pollock examined P.U.C. SUBST. R. 25.242(k)(1) and concluded that, for Standby
Service, cost-based standby rates should recognize system-wide costing principles and must not be
discriminatory. According to his analysis, the SMS demand charges should be $0.82 per kW for
delivery at transmission and $2.64 per kW for delivery at distribution. He also determined that cost-
based energy charges should be as follows:990


                         Cost-Based Schedule SMS Non-Fuel Energy Charges
                                            (¢ per kWh)
                                 Delivery Voltage            On-Peak Off-Peak

                          Distribution (less than 69KV)      0.955¢     0.639¢
                            Transmission (69KV and
                                     greater)                0.916¢     0.614¢


          Mr. Pollock explained that, on average, 7 percent of Schedule SMS billing demand was
coincident with ETI’s summer month system peaks. This compares to 74 percent for Schedule
LIPS; thus, the ratio of the SMS to LIPS coincidence factors is 12 percent. By Mr. Pollock’s
calculations, the resulting demand charge for transmission service would be $0.82 per kW ($7.07 x
12 percent), and the corresponding SMS distribution demand charge would be the sum of the
transmission charge and the Schedule LIPS distribution demand charge, or $2.64 per kW ($0.82 +
$1.82).991


989
   On-peak hours are from 1:00 p.m. to 9:00 p.m., Monday through Friday of each week, beginning on May
15 and continuing through October 15. In addition, fuel charges are priced at avoided energy cost as
calculated under Schedule LQF. TIEC Ex. 1 (Pollock Direct) at 72.
990
      TIEC Ex. 1 (Pollock Direct) at 73-74 and Ex. JP-15.
991
      Id. at 72-74.
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          Mr. Pollock testified that he combined production and transmission costs in deriving a
cost-based schedule SMS demand charge for transmission delivery, because both production and
transmission demand-related costs are allocated to customer classes using the A&E 4CP method.
This method recognizes that production/transmission plant is sized to meet the diversified summer
peak demands of all ETI customers. That is, Mr. Pollock stated, the 4CP demands are a primary
driver of the costs of the power plants, PPAs, and transmission facilities. As noted above,
Mr. Pollock contended and verified by analysis that a cost-based Schedule SMS demand charge
should be only 12 percent of the corresponding demand charge for Schedule LIPS.992


          Mr. Pollock also stated that he proposed to differentiate the standby demand charge by
delivery voltage because it more directly recognizes the different costs to provide service at
transmission and distribution voltage. He added that this recommendation is consistent with the
current Schedule SMS energy charges.993 However, Mr. Pollock did not apply the 12 percent
coincidence ratio to determine the distribution-related schedule SMS demand charge. He explained
that distribution facilities are electrically closer to customers, so a customer’s peak demand
determines how distribution facilities must be sized to ensure reliable service. He stated that ETI
recognized this driver by using maximum diversified demand to allocate distribution demand-related
costs. For this reason, Schedule SMS customers require the same amount of distribution capacity as
a similarly sized Schedule LIPS customer. Thus, according to Mr. Pollock, the Schedule SMS
distribution demand charge should be the same as the corresponding Schedule LIPS demand
charge.994


          Concerning energy charges, Mr. Pollock testified that the Schedule SMS energy charge
should reflect the composite Schedule LIPS energy charges, or 0.614¢ per kWh. In his view, a
Schedule SMS customer should also pay additional demand charges during on-peak hours, because
this would recognize that an SMS customer that purchases more energy during on-peak hours would
more closely resemble a LIPS customer. For this reason, cost-based on-peak energy charge should

992
      Id. at 75-77.
993
      TIEC Ex. 1 (Pollock Direct) at 77.
994
      Id. at 77-78.
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be a composite of the Schedule LIPS energy charge and the remaining demand charges (not
collected in the SMS demand charge). He calculated an additional on-peak energy charge of 0.303¢,
which yields a total on-peak energy charge of 0.917¢. Under this structure, an SMS customer that
experiences an outage would pay approximately the same for electricity as a LIPS customer.995

           In summary, Mr. Pollock contended that Schedule SMS should be reduced to more closely
reflect the cost of providing standby service as follows:996

                                  Cost-Based Schedule SMS Charges
                            Based on ETI’s Proposed Schedule LIPS Design
                                           Distribution     Transmission
                            Charge          (less than       (69kV and
                                              69kV)           greater)
                                     Billing Load Charge ($/kW)
                            Standby           $2.64            $0.82
                           Maintenanc
                                              $2.44            $0.62
                               e
                                    Non-Fuel Energy Charge (¢/kWh)
                           On-Peak       0.955¢          0.916¢
                           Off-Peak      0.639¢          0.614¢

           Using his recommended Schedule LIPS rate design, he proposed Schedule SMS charges
shown in the table below:997


                                          TIEC Proposed SMS Charges
                                                Distribution    Transmission
                                 Charge          (less than      (69kV and
                                                   69kV)          greater)
                        Customer Charge
                                                        $6,000
                         (Stand Alone)
                                     Billing Load Charge ($/kW)
                            Standby            $2.46            $0.79
                          Maintenance          $2.27            $0.60
                                      Non-Fuel Energy Charge (¢/kWh)
995
      Id. at 77-78; Ex. JP-15.
996
      Id. at 79.
997
      TIEC Ex. 1 (Pollock Direct) at 80.
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                        On-Peak             0.881¢             0.846¢
                        Off-Peak            0.575¢             0.552¢

            Mr. Pollock based his recommended charges on ETI’s proposed revenue requirements and
class revenue allocation. If the Schedule LIPS revenue requirement is reduced, the charges should
be correspondingly reduced. Mr. Pollock also added a customer charge, but he stated that the
customer charge should not apply if a Schedule SMS customer also purchased supplementary power
under another applicable rate.998


            To determine maintenance power charges, Mr. Pollock maintained the same relationship; that
is, the current maintenance power demand charge is 75 percent of the standby power demand charge.
He stated that the 75 percent should apply to the production/transmission component of the
recommended standby power demand charge because distribution costs are caused by maximum
demands occurring at any time, as previously discussed. This would result in a $0.20 and
$0.19 per kW differential based on ETI’s proposed and Mr. Pollock’s recommended Schedule LIPS
designs, respectively.999


            The ALJs note that Mr. Pollock’s suggested changes to Schedule SMS are extensive. For
instance, he introduced a $6,000 customer charge and, for the monthly billing load (demand)
charges, he introduced separate rates for distribution and transmission customers.1000


            Ms. Talkington testified that Mr. Pollock erred in using load data for the period of 2007
through 2011 to develop a coincidence factor that he then uses to develop a lower back-up and
maintenance demand charge for transmission-level customers, while significantly increasing the
charge for distribution-level customers. She also stated that Mr. Pollock’s proposal fails to
recognize the “readiness to serve” aspect of standby service. ETI must be ready to serve the load




998
       Id. at 79.
999
       TIEC Ex. 1 (Pollock Direct) at 80.
1000
       TIEC Ex. 1 (Pollock Direct) at 80.
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represented by the largest generation unit taking standby service, plus account for the forced outage
rates for all other existing customer-owned generators.1001


          Ms. Talkington also stated Mr. Pollock failed to recognize that standby load does not lend
itself to the typical rate design practices. She opined that the cost of providing SMS service is not
driven only by the degree to which standby customers contribute to peak demand, but also by the
Company’s obligation to serve whenever called upon. This is the major reason Schedule SMS is not
included in the development of allocation factors.1002


          Ms. Talkington admitted that she is not familiar with how ETI originally developed
Schedule SMS, but stated that she knows that when a customer takes back-up or maintenance
service, costing is generally designed to mimic what the customer would have paid on standard rates,
absent the use of its own generator. She concluded that Mr. Pollock’s analysis is over-simplified
and incomplete.1003


          In rebuttal testimony, Ms. Talkington proposed a new rate design for SMS service, including
a new service, Non-Reserved Service, which is an optional service designed to supplement
Maintenance Service. ETI’s new SMS proposal increases ETIs test year base rate revenues by
53.27 percent, with an overall increase of $5.1 million. ETI did not include this rate increase in its
notice.1004 Accordingly, the ALJs determine that ETI’s new SMS proposal is not an option to be
considered in this case.


          Commission Staff does not oppose ETI’s request to retain its current Schedule SMS.




1001
       ETI Ex. 67 (Talkington Rebuttal) at 20-21.
1002
       ETI Ex. 67 (Talkington Rebuttal) at 21.
1003
       ETI Ex. 67 (Talkington Rebuttal) at 21-22.
1004
    PURA § 36.102 and P.U.C. PROC. R. 22.51 require a utility to publish notice of its intent to change rates,
with proposed revisions of tariffs and a detailed statement of each proposed change, the effect it is expected to
have on revenues, the class and number of customers affected by the change.
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          ETI did not demonstrate how its current rates are just and reasonable. Rather, ETI’s
evidence on the reasonableness of Schedule SMS is conclusory and insufficient in light of
Mr. Pollock’s testimony that the rates are not cost-based. Moreover, although Ms. Talkington
indicated her concern with Mr. Pollock’s analysis, she provided no quantitative support for her
concern. The ALJs, however, are concerned that Mr. Pollock’s suggested changes are not
accompanied by a rate impact analysis. And, as noted above, his suggested changes are extensive.
Mr. Pollock’s recommendations included a significant increase in the charge for distribution-level
customers. Consistent with his Schedule LIPS recommendation, Mr. Pollock also included a $6,000
customer charge when no previous customer charge existed. Again, there is no analysis as to the
effect such a charge would have on customer bills. The testimony of witnesses Benedict, Abbott,
Higgins, and Pevoto caution that gradualism should be considered in rate design. As noted by Mr.
Higgins, “full movement to cost-based rates in a single step is sometimes opposed on the grounds of
intra-class rate impacts.”1005 However, the rate impact at this time is not known.


          Based on the evidence and discussion above, the ALJs recommend adoption of Mr. Pollock’s
suggested changes to Schedule SMS , with the exception of a $6,000 customer charge. Consistent
with the ALJs’ recommendation that a new LIPS charge of $630 is reasonable, the SMS charge
should be limited to $630 and, as suggested by Mr. Pollock, not apply if a Schedule SMS customer
also purchased supplementary power under another applicable rate.


          6. Additional Facilities Charge (AFC)

          Mr. Pollock testified that Schedule AFC is the mechanism for charging customers directly
for the costs of transformers, breakers and lines when those facilities provide service only to specific
customers. Some of these facilities are booked to transmission accounts while others are booked to
distribution accounts. Schedule AFC is applied as a percentage of the original (un-depreciated) cost
of the facilities.1006




1005
       Kroger Ex. 1 (Higgins Direct) at 10.
1006
       TIEC Ex. 1 (Pollock Direct) at 81.
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          TIEC contends that the Schedule AFC charges should be revised. According to Mr. Pollock,
the current charges exceed ETI’s ownership and O&M costs; therefore, he recommended that the
monthly charges in Schedule AFC be reduced. Under this rate schedule, there are two separate
pricing options. Option A charges 1.49 percent per month; Option B applies when a customer elects
to amortize the direct assigned facilities over a shorter term, ranging from one to ten years. Thus,
the Option B Monthly Recovery Term charge varies depending on the length of the amortization
period of the directly assigned investment. A 0.453 percent Monthly Post-Recovery term charge
also applies after a facility has been fully depreciated. ETI did not propose to change either the
Option A or Option B charges in Schedule AFC.1007


          According to Mr. Pollock’s analysis, charges imposed under Option A should be
1.20 percent per month under ETI’s proposed revenue requirements. Under Option B, Mr. Pollock
proposes various changes to the Recovery Term charges, and reduces the Monthly Post-Recovery
term to 0.35 percent per month. Further, if the Commission approves a lower base revenue
requirement than ETI has proposed, Mr. Pollock stated that the recommended Schedule AFC
charges (both Option A and Option B) should be reduced in proportion to any authorized reduction
in ETI’s proposed rate of return, O&M expense, and property tax expense.1008


          In reaching this recommendation, Mr. Pollock used two different methods to derive a cost-
based rate: a levelized cost analysis and a revenue requirement analysis. The former resulted in an
Option A rate of 1.20 percent per month, and the revenue requirement analysis resulted in a
weighted average rate of 1.18 percent. For Option B charges, Mr. Pollock also used a levelized cost
analysis for each of the Option B amortization periods, which resulted in lower charges.1009


          ETI witness Talkington disagrees with Mr. Pollock’s description of Schedule AFC. She
testified that the rate schedule encompasses the costs associated with the installation of facilities
other than those normally furnished. Or, under one option, the rates are like a monthly rental charge


1007
       Id. at 82-85.
1008
       TIEC Ex. 1 (Pollock Direct) at 81-85 and at Exs. JP-17 and JP-18. See ETI Ex. 3, Sch. Q-8-8 at 24.
1009
       TIEC Ex. 1 (Pollock Direct) at Ex. JP-18.
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paid for facilities that would not normally be supplied by the Company. She also stated that
Mr. Pollock’s example of facilities (transformers, breakers and lines) is understated.1010


          ETI contends that revisions to this discretionary rate are unwarranted at this time. The
Commission approved this rate structure (and rate) in Docket No. 16705. Moreover, ETI witness
Talkington testified that this rate is voluntary—a customer has alternatives beyond those offered by
ETI. Therefore, it is actually a market-driven rate. If a customer does not want to use this schedule
to obtain the services it provides, the customer can secure services through other sources—either
ETI-owned or otherwise. Ms. Talkington further stated that Mr. Pollock’s suggested changes would
be detrimental to the customers who do not have AFC rates because the AFC revenue is treated as an
offset to the revenue requirement to the rate classes.1011


          Staff does not oppose ETI’s request to retain the AFC rate as it is currently designed.


          The ALJs find insufficient support in the record to retain ETI’s Schedule AFC as-is. As
noted by TIEC, there is no evidence in this case to support ETI’s claim that: (1) the rate is a
voluntary rate; (2) there are other options in the market for customers; or (3) that the rate continues
to be based on a cost that the market will bear (as the Commission found years ago in Docket
No. 16705).1012 While Ms. Talkington disagreed with Mr. Pollock’s proposal because he did not
take into consideration the scope of facilities provided and that his proposal could be detrimental to
other ratepayers because ETI’s revenues from this rate will decrease, she did not quantify her
concerns.1013 The evidence supports a change to Schedule AFC that will move the rate more
towards costs, and TIEC’s proposals are the only ones for which there is evidence in the record. The
ALJs further agree with Mr. Pollock that his numbers should be reduced in proportion to any
authorized reduction in ETI’s proposed rate of return, O&M expense, and property tax expense.



1010
       ETI Ex. 67 (Talkington Rebuttal) at 31.
1011
       ETI Ex. 67 (Talkington Direct) at 27-28.
1012
       See Docket No. 16705, Final Order, FoFs 292-296.
1013
       Tr. at 1437, 1439-1440.
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PUC DOCKET NO. 39896


           7. Large General Service (LGS)

           Kroger witness Kevin C. Higgins testified that the LGS rate schedule serves customers with
monthly billing demands between 300 kW and 2,500 kW. ETI proposes to increase the LGS
demand charge from $8.56 per kW-month to $10.25 per kW-month and to increase the energy
charge from $.00854 per kWh to $.01023 per kWh. The Company proposes no change in the
customer charge of $425.05 per month.1014


           Mr. Higgins testified that ETI’s proposed LGS demand charge would recover only
72 percent of LGS demand-related costs. To compensate for the resultant revenue shortfall, the LGS
energy charges proposed by ETI would significantly over-recover energy-related costs. Specifically,
the overall LGS energy charge is proposed to be 428 percent of base energy costs. In addition,
although the customer charge is proposed to be unchanged, it is set at 328 percent of cost. If,
instead, the LGS customer charge were set at cost, it would only be $129.60 per month.1015


           Mr. Higgins illustrated his findings in the table below:1016


                           LG Total Class Functionalized Cost Recovery

         Functions         Costs             Collected in     (Under)/Over         Percentage
                                                Rates          Collection          Recovered
         Demand         $46,266,083           $33,116,674      $(13,149, 409)            71.6%
         Energy         $3,6625,811           $15,556,253        $11,920,442            427.9%
         Customer          $561,445            $1,841,316         $1,279,871            328.0%
         Total          $50,463,339           $50,514,243            $50,904


           Mr. Higgins stated that if a utility proposes a demand charge that is below the cost, it is going
to seek to recover its class revenue requirement by over-recovering its costs in another area,
typically through an energy charge that is above unit energy costs. In his opinion, for LGS, when
demand charges are set below costs and energy charges are set above cost, customers with relatively

1014
       Kroger Ex. 1 (Higgins Direct) at 7.
1015
       Id. at 8.
1016
       Kroger Ex. 5.
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higher load factors are required to subsidize the costs of lower load factor customers within the rate
class. The subsidy is different for each higher load factor customer (a customer whose load factor is
greater than the average for the rate schedule) and consists of the net increase in rates paid by these
customers as a result of setting energy charges above energy costs and demand charges below
demand related costs. When the customer charge is set significantly above costs, smaller customers
are overcharged and subsidize the larger customers.1017


          Recognizing that a full movement towards cost-based rates (without gradualism) in a single
step may create intra-class rate impacts, Mr. Higgins proposed the following changes to better align
costs:1018


                                         ETI                       Kroger
                                       Proposed      % of         Proposed          % of
                      Functions
                                        Charge       Cost          Charge           Cost
               Demand ($/kW)            $10.25       72%           $12.81           90%
               Energy ($/kWh)          $0.01023      428%         $0.00513         216%
               Customer ($/Mo)          $425.05      328%          $260.00         201%


          Mr. Higgins developed his proposed rate impacts, which indicated a smaller rate impact on
higher load factor customers than those with low load factors. He found them to be comparable to
the rate impact found in ETI’s proposed rates.1019


          ETI witness Talkington did not object to gradually moving rates toward setting demand
energy and customer components closer to cost of service in the LGS class.1020


          Based on principles of cost-based rates and of gradualism, Staff witness Abbott
recommended a decrease in the LGS customer charge to $397.02 from the current (and Company

1017
       Kroger Ex. 1 (Higgins Direct) at 9.
1018
       Id. at 10-11.
1019
       Id. at 11, Ex. KCH-3.
1020
       Tr. at 1452.
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PUC DOCKET NO. 39896


proposed) $425.05, and an increase in the energy charges, which is less than the increase proposed
by the Company.1021


             The ALJs found Mr. Higgins’ proposed changes reasonable and well supported.
Schedule LGS should be amended as proposed by Kroger. Schedule LGS also has a demand ratchet,
and the ALJs’ recommendation for the elimination of ETI’s LIPS demand ratchet is applicable to
this class.


             8. General Service (GS)

             Based on principles of cost-based rates and of gradualism, Staff witness Abbott
recommended a decrease in the GS customer charge to $39.91 from the current (and Company
proposed) rate of $41.09. Staff also recommended a decrease in the energy charges.1022


             No party disputed Staff’s recommendations, which the ALJs adopt. Schedule GS also has a
demand ratchet, and the ALJs’ recommendation for the elimination of ETI’s LIPS demand ratchet is
applicable to this class.


             9. Residential Service (RS)

             ETI’s RS rate schedule is composed of two elements: a customer charge of $5 per month
and a consumption-based energy charge. The Energy charge is a fixed rate of 5.802ȼ per kWh from
May through October (Summer). In the months November through April (Winter), the rates are
structured as a declining block, in which the price of each unit is reduced after a defined level of
usage. For instance, the same energy charge of 5.802ȼ applies, but only for each of the first 1,000
kWh consumed. Each kWh consumed beyond 1,000 is billed at a lower rate of 3.834ȼ.1023




1021
       Staff Ex. 7 (Abbott Direct) at 25-27.
1022
       Id.
1023
    OPC Ex. 6 (Benedict Direct) at 41, Ex. NAB-1, ETI’s Response to State RFI No. 4-17; ETI Ex. 67
(Talkington Rebuttal) at 9.
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          ETI proposes to retain the general structure of the RS rate design but proposes an increase in
the dollar amount of each rate element. OPC witness Benedict noted ETI’s proposed changes in his
testimony, as set out below:1024


                                                           ETI                ETI             Percent
                       Rate Element                       Current           Proposed          Increase
             Customer Charge (per month)                $5.00               $6.00             20.0%
             Energy Charge (Summer, all                                                       25.3%
                                                        $0.05802            $0.07268
             kWh)
             Energy Charge (Winter, kWh ≤                                                     25.3%
                                                        $0.05802            $0.07268
             1000)
             Energy Charge (Winter, kWh >                                                     25.2%
                                                        $0.03834            $0.04799
             1000)


          OPC criticized ETI’s declining block rate structure as being contrary to energy efficiency
efforts. OPC witness Benedict noted that under ETI’s proposed rate structure, once kWh usage
exceeds 1,000 in a winter month, the per-kWh cost of consumption falls by 34 percent. Thus,
because a declining block rate structure lowers the per-unit rate for high levels of consumption,
heavy users are induced to consume more than they would otherwise. In his view, this runs contrary
to the Legislature’s goal of reducing both energy demand and energy consumption in Texas, as
stated in PURA § 39.905:


          (a) It is the goal of the legislature that: . . . (2) all customers, in all customer classes,
          will have a choice of and access to energy efficiency alternatives and other choices
          from the market that allow each customer to reduce energy consumption, summer
          and winter peak, or energy costs.

Therefore, Mr. Benedict recommended that the declining block rate be phased out over time. He
stated this would ease the transition to a rate structure without a declining block, and it would allow
time for customers to switch to more efficient heating systems. Mr. Benedict proposed that the
phase-out take place over three rate cases, beginning with a one-third reduction in the block
differential proposed by ETI in this case. Reducing ETI’s proposed block differential from 2.469ȼ

1024
       OPC Ex. 6 (Benedict Direct) at 42.
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to 1.645ȼ accomplishes the initial one-third reduction, as illustrated below (using ETI’s requested
revenue requirement):1025


                                                                              Reduced
                                        ETI          ETI        Percent      Block Rate     Percent
         Rate Element                 Current     Proposed      Increase     Differential   Increase
 Customer Charge (per month)           $5.00        $6.00        20.0%          $6.00         20%
 Energy Charge (Summer, all                                      25.3%                       23.1%
                                      $0.05802    $0.07268                    $0.07141
 kWh)
 Energy Charge (Winter, kWh ≤                                     25.3%                      23.1%
                                      $0.05802    $0.07268                    $0.07141
 1000)
 Energy Charge (Winter, kWh >                                     25.2%                      43.3%
                                      $0.03834    $0.04799                    $0.05496
 1000)


Mr. Benedict stated that his proposal related to an intra-class rate design issue and was not intended
to affect the amount of revenue to be collected from the residential class or any other class. If,
however, the Commission approves a different revenue requirement for the residential class to
reflect various proposed adjustments, rates for the class will need to be recomputed regarding a
reduced block differential1026


          Staff generally agreed with OPC’s recommendation for a reduction in the rate differential
between the residential winter kWh ≤ 1000 block and the winter kWh > 1000 block, due to the
inconsistency between the incentives produced under declining block rates and the State’s energy
efficiency goals. Staff witness Abbott stated that the extreme cold weather event of February 2011
demonstrated a need to incentivize wintertime energy efficiency measures, or at least a need to avoid
encouraging excess energy usage. Therefore, Mr. Abbott agreed that some reduction in the rate
block differential is warranted to better encourage wintertime energy conservation at the margin.1027


          ETI witness Talkington testified that the RS rates are cost-based with a declining block rate
in winter. According to Ms. Talkington, residential load factors in winter increase as energy usage
increases, and there is also a decrease in the fixed unit cost ($/kWh) as energy usage increases. She


1025
       OPC Ex. 6 (Benedict Direct) at 43-45.
1026
       OPC Ex. 6 (Benedict Direct) at 46.
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PUC DOCKET NO. 39896


provided analysis to support her position.1028 Ms. Talkington explained that residential rates do not
include demand charges because of the absence of residential demand meters. However, residential
energy rates can be structured the same as the non-residential classes; that is, customer charge,
demand charge and energy charge. She developed residential rates on this basis to show that the
declining block rate is appropriate to account for reductions in the cost of service to residential
customers as consumption increases. With no declining block rate, high load factor customers are
disadvantaged as the customer charge is reduced and the demand charge is moved into the energy
charge. She believes that declining block rates alleviate the disadvantage.1029


           Ms. Talkington illustrated the impact of Mr. Benedict’s suggestion to phase out the declining
block rate for RS customers. Approximately 54 percent of ETI’s residential customers use more
than 1,000 kWh in January and February. For a customer using 3,000 kWh in a winter month of
November-April, this customer’s bill would increase by 16.28 percent or about $48 over current
rates. (Of ETI’s total number of RS customers, approximately 10 percent use 3,000 kWh or more in
the months of January and February.) For that same customer, ETI’s as-filed proposal shows an
increase of 11.96 percent or approximately $35. Mr. Benedict’s proposal is $13 greater than ETI’s
proposal for one winter month at 3,000 kWh. That dollar amount is over a third of the total increase
ETI is proposing.1030


           After Mr. Benedict’s proposed phase-out is completed, based on the proposed residential
rates in the Company’s case, the residential rate would be $0.06887 per kWh in both summer and
winter. A customer using 3,000 kWh in a winter month of November-April would see an increase of
24.89 percent or about $73 over current rates. After the final phase out, Mr. Benedict’s proposal is
$38 per month greater than ETI’s as-filed proposal of $35 for one winter month at 3,000 kWh.1031



1027
       Staff Ex. 7 (Abbott Direct) at 27.
1028
       ETI Ex. 67 (Talkington Rebuttal) at 13, Ex. MLT-R-1.
1029
       Id. at 14.
1030
       Id. at 15.
1031
       Id. at 15-16.
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          Ms. Talkington further noted that rate design professionals always take into consideration the
effect on customer bills. Even though Mr. Benedict proposes to implement the change over the next
three rate cases, she concludes there will still be winners and losers within the residential class as a
result of his proposed change. According to Ms. Talkington, some customers have made decisions
about investing in electric appliances based on the current rate design. The elimination of the
declining block in the winter time changes the economics of customer decisions that have already
been made. She believes that great caution needs to be exhibited and very good reasons need to be
demonstrated before changes are made to the rate design. She recommended that if a change to the
rate structure is recommended, the initial phase-in should be reduced to 10 percent rather than one-
third and subsequent reductions should be reviewed for consideration at the occurrence of each rate
case filing and not mandated at this time.1032


          The ALJs concur with OPC and Staff that the structure of the declining block winter rates
provide a disincentive to energy efficiency. However, ETI provided evidence that OPC’s suggested
changes, combined with ETI’s proposed rate increase, will have too great an impact. OPC suggested
a one-third reduction in the differential, while Ms. Talkington suggested a 10 percent reduction, with
subsequent reductions reviewed before being mandated. The ALJs recommend an initial 20 percent
reduction, which should alleviate some of ETI’s concerns but still reduce the block differential
sufficiently to move towards compliance with the energy goals set out in PURA. The ALJs further
recommend that 20 percent subsequent reductions of the differential be required in the next three
rate cases unless ETI provides sufficient evidence that such changes are unjust and unreasonable.


  XI.      FUEL RECONCILIATION [Germane to Preliminary Order Issue Nos. 21-31]

          In the application, ETI seeks to reconcile approximately $1.3 billion in fuel and purchased
power expenses incurred over the 24 month Reconciliation Period. Summaries of ETI’s total fuel
and purchased power expenses and over/under recovery balance are shown below.




1032
       ETI Ex. 67 (Talkington Rebuttal) at 15-17.
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PUC DOCKET NO. 39896


                                                  Fuel Reconciliation
Gas and Oil                                                                                              $616,248,686
Emissions Allowance                                                                                           360,236
Coal                                                                                                       90,821,317
Total Fuel:                                                                                              $707,430,239

Purchase Power Expense                                                                                    990,041,434
Off-system Sales Revenues                                                                               (376,671,969)
Total Purchased Power:                                                                                   $613,369,465

Total Fuel Costs:                                                                                     $1,321,799,704

Over-recovery Balance:                                                                                   $243,339,353

Special Circumstances                                                                                           $99,715
Sources: ETI Ex. 3 Schedules I-16, H-12.4a-g, H-12.5b-e, I-21; ETI Ex. 11 (McCloskey Direct); ETI Ex. 23 (Zakrzewski
Direct).


          ETI contends, and the evidence presented at the hearing demonstrates, that these fuel factor
expenses were eligible for reconciliation and were reasonable and necessary to provide reliable
service to ETI’s customers during the Reconciliation Period. With the exception of three minor
issues that are discussed below, none of the intervenors raised a substantive issue with respect to
ETI’s fuel reconciliation request.

          During the Reconciliation Period, ETI’s Texas fuel factor revenues over-recovered total fuel
and purchased power expense by $243,339,353, inclusive of interest. The Commission authorized
the refund of the fuel over-recovery balance in Docket Nos. 37580, 38403, and 38967. ETI proposes
that the amount of any fuel over-recovery balance not already refunded or authorized for refund be
rolled forward as the beginning balance for the next reconciliation period.1033

          P.U.C. SUBST. R. 25.236(d)(1) states that in a fuel reconciliation proceeding, the utility has
the burden of showing that:

          (A)      its eligible fuel expenses during the fuel reconciliation period were
                   reasonable and necessary expenses incurred to provide reliable electric
                   service to retail customers;


1033
       ETI Ex. 40 (Thiry Direct) at 7.
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       (B)     if its eligible fuel expenses for the reconciliation period included an item or
               class of items supplied by an affiliate of the electric utility, the prices charged
               by the supplying affiliate to the electric utility were reasonable and necessary
               and no higher than the prices charged by the supplying affiliate to its other
               affiliates or divisions or to unaffiliated persons or corporations for the same
               item or class of items; and
       (C)     it has properly accounted for the amount of fuel-related revenues collected
               pursuant to the fuel factor during the reconciliation period.


       In Docket No. 15102, an EGSI fuel reconciliation case, the Commission explained the
traditional prudence standard to be applied in reviewing decisions made by the utility:


       The exercise of that judgment and the choosing of one of that select range of options
       which a reasonable utility manager would exercise or choose in the same or similar
       circumstances given the information or alternatives available at the point in time
       such judgment is exercised or option is chosen.

       There may be more than one prudent option within the range available to a utility in
       any given context. Any choice within the select range of reasonable options is
       prudent, and the Commission should not substitute its judgment for that of the utility
       . . . . The reasonableness of an action or decision must be judged in light of the
       circumstances, information, and available options existing at the time, without
       benefit of hindsight.1034

       ESI purchases power and procures fossil fuels on behalf of the individual Operating
Companies. Fossil fuel costs are borne directly by the Operating Company that contracts for and
uses the fuel. Once resources are procured to meet forecasted demand, the system is operated during
the current day using all of the resources available to the system to meet the total system demand.
Throughout the course of the day, system operators may modify planned operations to maintain
reliability, take advantage of less-expensive resources in the hourly wholesale power markets, or
make off-system sales. For example, when spot market power purchases are available at a cost




1034
   Application of Gulf States Utilities Company to Reconcile its Fuel Costs, Docket No. 15102, Order on
Rehearing at 2 (Jun. 24, 1997).
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lower than the cost of energy that can be generated by units owned by the Operating Companies, that
energy is purchased to displace owned generation, subject to operating constraints.1035


          Expenses for coal, gas, power purchases, and fuel oil are incurred directly by the respective
Operating Company. For example, if coal is purchased for ETI’s share of Nelson Station, Unit 6,
then ETI is responsible for the invoiced cost and makes payment directly to the supplier. Wholesale
power, purchased and sold for the system, however, is accounted for per the terms of the System
Agreement. After dispatch, or after-the-fact, the System Agreement prescribes an accounting
protocol to bill the costs of operating the system to the individual Operating Companies.1036


          The following Fuel Reconciliation-related issues were uncontested:


              ¾ Natural Gas Purchases

          ETI witness Karen McIlvoy presented direct testimony describing ETI’s natural gas
procurement policies and strategies. She explained that the Company buys gas through a long-term
contract with Enbridge, through participation in the monthly and daily markets depending on fuel
needs, and on a delivered-to-plant basis or arrange for transportation to the plant. Ms. McIlvoy
described how the gas buyers for ETI survey the markets and solicit offers for gas supplies.
Ms. McIlvoy also provided a comparison of the Company’s gas costs to the Inside FERC and Gas
Daily published indices for the Houston Ship Channel.1037 No party challenged the Company’s
natural gas purchases.


              ¾ Fuel Oil

          Ms. McIlvoy testified that the Company purchased fuel oil for start-up and flame
stabilization at certain units. Fuel oil can also be used for emergency back-up fuel or as an economic
alternative to natural gas at certain units. During the Reconciliation Period, the Company purchased


1035
       ETI Ex. 40 (Thiry Direct) at 18-21.
1036
       ETI Ex. 39 (Cicio Direct) at 31-37.
1037
       ETI Ex. 28 (McIlvoy Direct) at 23, Ex. KDM-3.
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all fuel oil on a short-term basis from spot market sources after solicitation of bids from multiple
potential suppliers.1038 No party contested ETI’s fuel oil costs.


                ¾ Longer-Term Purchased Power

             ETI witness Robert R. Cooper addressed the Entergy system’s long-term planning process
and described the Strategic Resource Plan process. He explained how the system determined its
capabilities and needs for additional resources to reliably serve system load requirements.
Mr. Cooper described the process by which the system developed requests for proposals and
analyzed a combination of capacity and firm energy contracts to satisfy the system’s identified
resource needs.1039 A portion of these system purchases was allocated to ETI. No party proposed a
disallowance of these purchases on the basis of prudence.


                ¾ Short-Term Purchased Power

             Ms. Thiry described the Power Marketing Team’s procurement strategies, practices and
procedures during the Reconciliation Period. Ms. Thiry testified that the Power Marketing Team
fulfilled its objective of purchasing energy in the wholesale market when it was more economical
than using the system’s generation and in order to maintain system reliability.          Ms. Thiry
demonstrated that third-party purchases for the system compared favorably to market price indices
and to proxy costs of avoided generation.1040 The Power Marketing Team maintained effective cost
controls and procured a diverse portfolio of product to provide electricity for customers at a
reasonable cost.1041 No party contested the prudence of ETI’s short-term power purchases.


                ¾ Coal Commodity and Transportation

             ETI has ownership interest and/or obtains power through Schedule MSS-4 of the Entergy
System Agreement, in two coal-burning generating units – Nelson and BCII/U3. ETI owns a

1038
       ETI Ex. 28 (McIlvoy Direct) at 5-6.
1039
       ETI Ex. 34 (Cooper Direct) at 6-10.
1040
       ETI Ex. 40 (Thiry Direct) at 24.
1041
       Id.
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29.75 percent interest in Nelson 6 and operates the unit. ETI owns a 17.85 percent interest in
BCII/U3, but the unit is operated by a third party. ETI witness Ryan Trushenski, the Manager of
Coal Supply for ESI, testified that ETI prudently managed its coal supply and transportation
expenses during the Reconciliation Period.1042


          With respect to coal and transportation expenses at Nelson 6, ETI obtained coal during the
Reconciliation Period under a supply contract previously reviewed by the Commission, and entered
into a new coal supply contract after a competitive bid process. ETI chose the supplier with the
lowest priced coal that met the specifications necessary for use at Nelson 6. Similarly, ETI arranged
for transportation of coal according to transportation contracts previously reviewed in prior fuel
reconciliations. When those contracts expired, ETI initiated a competitive bid process and chose the
lowest cost option available that met its requirements. With respect to BCII/U3, ETI incurred costs
to run the unit and took reasonable steps to ensure that the third party operator properly charged for
coal and transportation expenses under an arrangement previously reviewed and approved in prior
fuel reconciliations.1043 No party challenged the reasonableness and necessity of ETI’s coal or
transportation expense during the Reconciliation Period


          The three contested issues are discussed below.


A.        Spindletop Gas Storage Facility

          During the Reconciliation Period, ETI incurred $10,261,663 of non-fuel expense associated
with operating the Spindletop Facility. Cities challenged ETI’s use of the Spindletop Facility,
arguing that the costs of operating it outweigh the benefits gained from it. For the same reason he
challenged the Spindletop Facility costs associated with rate base, Cities witness Nalepa also
challenges ETI’s non-fuel expense associated with the facility.           Specifically, Mr. Nalepa
recommends that ETI’s total fuel reconciliation balance be reduced by $6,595,290, which he
calculates as the difference between the $10,261,633 non-fuel operational costs associated with the
Spindletop Facility over the Reconciliation Period and the costs of alternative sources of providing a

1042
       ETI Ex. 33 (Trushenski Direct) at 2.
1043
       Id. at 11-13.
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reliable and flexible gas supply over the same period.1044 In Section V.H., above, the ALJs rejected
Cities’ contention that the Spindletop Facility is not used or useful. For the same reason they
rejected Cities’ Spindletop Facility arguments relevant to rate base, the ALJs also reject Cities’
Spindletop Facility arguments relevant to Fuel Reconciliation.


B.        Use of Current Line Losses for Fuel Cost Allocation

          Cities propose that the allocation of fuel costs incurred over the Reconciliation Period reflect
the current line loss study performed by ETI for this case and recommended for approval on a going
forward basis. In the fuel reconciliation case, ETI proposes to allocate costs to customers using a
line loss study performed in 1997, which Cities claim does not reflect the current cost of providing
service to the current wholesale customers and to the various retail customers.1045 According to
Cities, updating ETI’s allocation of fuel costs to reflect current line losses and the cost of providing
service to customers results in a $3,981,271 reduction to the Texas retail fuel expenses incurred over
the Reconciliation Period.1046


          ETI responds that the Cities’ recommendation is unprecedented.               It notes that the
Commission’s substantive rules require use of “a commission-approved adjustment to account for
line losses corresponding to the voltage at which the electric service is provided.”1047 Moreover,
ETI argues that retroactive use of new loss factors to calculate its fuel over/under-recovery balance
would result in a mismatch between the revenues recovered under the fuel factor and the costs billed
and allocated to the various customer classes.1048


          Fuel costs are collected through Commission-approved fixed fuel factors. One of the
elements the fuel factor is required to take into account is line losses.                P.U.C. SUBST.
R. 25.237(c)(2)(B) states that the utility must prove that: “the proposed fuel factors utilize a

1044
       Cities Ex. 6 (Nalepa Direct) at 42-43; Cities Initial Brief at 84.
1045
       Cities Ex. 6 (Napala Direct) at 44; see also Tr. at 1469-1470.
1046
       Cities Ex. 6 (Napala Direct) at 47, Table 14.
1047
       ETI Ex. 58 (McCloskey Rebuttal) at 2, quoting P.U.C. SUBST. R. 25.237(c)(2)(B) (emphasis added).
1048
       Tr. at 1484.
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commission-approved adjustment to account for line losses corresponding to the voltage at which the
electric service is provided.”1049 If the Commission were to adopt Cities’ recommendation that the
newly-developed line losses be used in the reconciliation of fuel costs, the allocation of those costs
would not match the collections (determined through the use of historical line losses). This
mismatch could result in some customers receiving more than they are entitled and others receiving
less than they are entitled. The ALJs find that the Commission’s rules require the use of
Commission-approved line losses that were in effect at the time fuel costs were billed to customers
in a fuel reconciliation. The ALJs, therefore, recommend that the Commission reject the Cities’
proposed adjustment.


C.           ETI’s Special Circumstances Request

             In the application, ETI seeks to include $99,715 in the Fuel Reconciliation to allow it to
recover “the reversal of certain credits that were previously included in the Company’s [Incremental
Purchased Capacity Rider] Rider IPCR.”1050 ETI witness Zakrzewski explained that the FERC
revised the amount of purchased capacity-related production costs allocable to ETI through the
FERC-approved Rough Production Cost Equalization mechanism for allocating production costs
among the Operating Companies. As Mr. Zakrzewski explained, the result of the decision was a
recalculation of ETI’s capacity costs recoverable through the Commission-approved Rider IPCR,
which expired during the Reconciliation Period.1051


             During the hearing, no party contested ETI’s special circumstances request of $99,715 with
regard to the IPCR-related adjustment. For the first time in its Initial Brief, however, Cities opposed
the request, asserting that it conflicts with the settlement reached in Docket No. 37744.1052 The
ALJs are not swayed by Cities’ argument. As pointed out by ETI,1053 Cities provided no testimony
or other evidence to support its position. Furthermore, Cities failed to explain how a settlement

1049
       P.U.C. SUBST. R. 25.237(c)(2)(B) (emphasis added).
1050
       ETI Ex. 23 (Zakrzewski Direct) at 13.
1051
       Id.
1052
       Cities Initial Brief at 86.
1053
       ETI Reply Brief at 93.
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agreement reached in Docket No. 37744 could or should trump the FERC’s jurisdiction to determine
the amount of purchased capacity costs attributable to ETI. The only evidence in the record supports
ETI’s recovery of these costs. Accordingly, the ALJs recommend that these FERC-imposed costs
should be found to be recoverable and Cities’ request to deny their recovery should be rejected.


          In summary, the ALJs conclude that, consistent with the requirements of P.U.C. SUBST.
R. 25.236(d)(1), ETI met its burden to prove that: (1) its eligible fuel expenses during the
Reconciliation Period were reasonable and necessary expenses incurred to provide reliable electric
service to its retail customers; (2) the prices charges by its affiliates were reasonable and necessary
and no higher than the prices charged by the supplying affiliates to other affiliates or to unaffiliated
persons; and (3) ETI has properly accounted for the amount of fuel-related revenues collected
pursuant to the fuel factor during the Reconciliation Period.


                                      XII.    OTHER ISSUES

A.        MISO Transition Expenses [Germane to Preliminary Order Issue Nos. 6-8 and Docket
          No. 39741 Preliminary Order Issue Nos. 1-9]

          Entergy is seeking to transfer operational control of the Entergy Operating Companies’
transmission assets to the MISO Regional Transmission Organization (RTO). ETI expects its share
of the costs for this transfer will include approximately $17 million of expense.1054 ETI has made
two alternate proposals to recover these expenses. ETI’s first proposal requests the Commission to
approve a deferred accounting of its transition expense incurred on or after January 1, 2011, and to
approve accrual of interest on the deferred amount at ETI’s overall rate of return. Under this
proposal, ETI would present the resulting regulatory asset for review in a future proceeding. ETI
originally requested this deferred accounting in Docket No. 39741, which was later consolidated into
this case for all purposes. In its Preliminary Order in Docket 39741, the Commission stated that it
had authority to allow such a deferral of costs “when it is necessary to carry out a provision of
PURA.” It also stated that whether ETI’s request met this requirement “hinges on the factual issue
of necessity . . . .”

1054
       ETI Ex. 42 (Lewis Supplemental Direct) at 5.
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          As an alternative proposal, ETI requested the Commission to include $4 million of transition
expense in base rates set in the present case, based on a three-year amortization of a total of
$12 million in MISO transition expenses. ETI’s Test Year MISO transition expenses totaled only
$916,535, but ETI’s request for deferred accounting addressed expenses incurred on or after
January 1, 2011, which is after the Test Year concluded. ETI argues that its request is a
conservative known and measureable change because the post-Test-Year expenses will be
significantly more than $4 million per year. Further, these costs would be removed from ETI’s cost
of service if its deferred accounting proposal is approved.


          As noted, ETI’s proposals concern MISO transition expenses incurred on or after January 1,
2011. However, ETI also incurred $263,908 in these expenses during the 2010 portion of the Test
Year. ETI has proposed a five-year amortization of this amount ($52,800 per year), assuming either
its primary proposal or its alternative proposal is adopted. However, if ETI’s primary and
alternative proposals are both rejected, ETI requested that no reduction be made to its total Test Year
amount of $916,535.1055


          Cities, TIEC, State Agencies, and Staff opposed ETI’s requests. They argue that ETI failed
to establish that the proposed deferred accounting is necessary to carry out a provision of PURA, as
required by the Commission’s Preliminary Order. They also contended that ETI’s alternate request
to include $4 million in base rates is not a known and measureable change and should be disallowed.


          The ALJs recommend that the Commission deny ETI’s request for deferred accounting of its
MISO transition expenses to be incurred on or after January 1, 2011. However, the ALJs do
recommend that the Commission authorize ETI to include $2.4 million of MISO transition expense
in base rates set in the present case, based on a five-year amortization of $12 million in total
projected expenses.




1055
       ETI Ex. 42 (Lewis Supplemental Direct) at 4 and Adjustment No. 16.L.
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          1.   Deferred Accounting

          In support of its deferred accounting request, ETI cited State v. Public Utility Comm’n of
Texas.1056 In that case, the Texas Supreme Court stated that a deferred accounting is “necessary”
when it will “ensure that the requirements of [PURA] are met.”1057 In ETI’s opinion, deferred
accounting is necessary in the present case to ensure that PURA §§ 36.051 and 36.003(a) are met
(i.e., that utilities have a reasonable opportunity to recover their expenses and receive reasonable
rates). ETI also relied on Hammack v. Public Utility Commission of Texas, which stated that “a need
. . . is a relative requirement, ranging from an imperative need to one that is minimal . . . .”1058


          ETI-witness Brett Perlman testified that deferred accounting is also necessary to ensure the
requirements of PURA § 31.001(c) are carried out.1059 That section encourages development of a
competitive wholesale electric market.          ETI noted that the Hammack opinion stated that
Section 31.001(c) amounts to a “legislative directive that the Commission formulate policies
responsive to the needs of the emerging competitive wholesale market.”1060 Therefore, ETI asserted
that RTO membership and deferred accounting are necessary because they will ensure that the
Commission meets its obligation under Section 31.001(c). More specifically, ETI stated, both RTO
membership and deferred accounting itself constitute examples of policies required by section
31.001(c) to support wholesale competition. Therefore, ETI argues that its request for deferred
accounting should be approved because it is necessary to carry out PURA §§ 36.051, 36.003, and
31.001(c).1061


          Cities argue that ETI’s request for deferred accounting of MISO transition expenses should
be denied because deferred accounting is not necessary to carry out any requirement of PURA.

1056
       883 S.W.2d 190 (Tex. 1994).
1057
       883 S.W.2d at 194.
1058
     Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.—Austin 2004, pet.
denied).
1059
       ETI Ex. 43 (Perlman Supplemental Direct) at 7.
1060
       131 S.W.3d at 723.
1061
   ETI’s Initial Brief at 231-234; ETI Ex. 42 (Lewis Supplemental Direct) at 2-4; ETI Ex. 43 (Perlman
Supplemental Direct) at 5-7.
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Cities witness James Brazell stated that ETI’s proposed transition to MISO is not mandatory, and the
anticipated expenses are not extraordinary. He added that ETI has been exploring membership in an
RTO for over ten years and those costs have historically been included in ETI’s base rates; therefore,
he concluded that deferred accounting was not necessary in the past and is not necessary now. Cities
stressed that ETI conceded that deferred accounting of these expenses is not necessary to maintain
its financial integrity, and in Cities’ opinion, both State v. Public Utility Comm’n of Texas,1062 and
the Commission’s Preliminary Order require a showing of impairment of financial integrity to
conclude that deferred accounting is necessary to comply with PURA § 36.051. Cities also stated
that ETI failed to show that deferred accounting is necessary to comply with PURA §§ 36.003 and
31.001(c); therefore, Cities argues that ETI’s request for deferred accounting should be denied.


          TIEC also opposed ETI’s request for deferred accounting, arguing that ETI failed to
demonstrate that it is necessary to carry out PURA §§ 36.051, 36.003, or 31.001(c). TIEC witness
Jeffry Pollock stated there is no indication that deferred accounting treatment is necessary for ETI to
earn a reasonable return on its invested capital or that denying the deferred accounting would
prevent ETI from having just and reasonable rates. Further, Mr. Pollock asserted there is no
evidence that a lack of deferred accounting treatment for ETI would prevent Entergy from pursuing
its MISO proposal.1063 Mr. Pollock added that ETI has incurred other similar costs to carry out
various purposes of PURA without deferred accounting. For example, since 2005, ETI has spent
nearly $20 million pursuing various similar activities, including transitioning to competition,
investigating RTO options, examining changes to the Entergy System Agreement, and supporting
the Entergy OATT. Yet, ETI did not seek deferred accounting for any of those costs. Finally,
Mr. Pollock testified that the projected transition costs are not material. He noted that ETI expects
to incur $17 million of transition costs.1064 This equates to $5.8 million per year, which is only
1 percent of ETI’s Test Year operating revenues, according to Mr. Pollock. In his opinion, this level




1062
       883 S.W.2d 190 (Tex. 1994).
1063
       TIEC Ex. 1 (Pollock Direct) at 46-47.
1064
       ETI Ex. 42 (Lewis Supplemental Direct) at 5.
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of MISO transition costs is easily subsumed in the normal variation in ETI’s year-to-year
expenses.1065


          TIEC also disagreed with ETI’s interpretation of State v. Public Utility Comm’n of Texas.1066
In TIEC’s view, that case held that deferred accounting is necessary only when needed to protect
the financial integrity of the utility.        Likewise, TIEC disagreed with ETI’s argument that
Hammack1067 held that “need” is a relative requirement that must be viewed in light of legislative
policy directives.1068 TIEC noted that Hammack had nothing to do with deferred accounting.
Instead, it was limited to the issue of whether, in granting a certificate of convenience and necessity
for a transmission line under PURA §37.056, the Commission should include evidence that
considered customers and market participants throughout the state.1069 In TIEC’s view, the
Hammack case is irrelevant in determining whether deferred accounting is necessary to carry out the
provisions of PURA §§ 36.003, 36.051, and 31.003(c). State Agencies made similar arguments.


          Commission Staff also argues that ETI did not establish why deferred accounting is
necessary to carry out a provision of PURA. In Staff’s view, the applicable court cases and other
precedent required ETI to show that deferred accounting is necessary to maintain its financial
integrity, in order to carry out the provisions of PURA § 36.051. Staff argues that the Commission’s
Preliminary Order did not reject the financial integrity standard when it stated: “[t]his standard is
not appropriate, however, for all circumstances and the Commission has applied different standards
in various circumstances.”1070 Rather, Staff stated, the Commission merely declined to designate a
specific standard.


1065
       ETI Ex. 1 (Pollock Direct) at 48-49 and Ex. JP-8.
1066
       883 S.W.2d 190 (Tex. 1994).
1067
     Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.—Austin 2004, pet.
denied).
1068
       ETI Initial Brief at 232-233.
1069
       Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 724 (Tex .App.−Austin 2004, pet. denied).
1070
   Application of Entergy Texas, Inc. for Authority to Defer Expenses Related to its Proposed Transition to
Membership in The Midwest Independent Transmission System Operator, Docket No. 39741 Preliminary
Order at 9 (Sep. 2, 2011).
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          Staff also rejected ETI’s argument that deferred accounting will “ensure that the Commission
meets its obligation under Section 31.001(c) to support the achievement of a competitive wholesale
market.”1071 First, Staff noted, the Commission stated in the Preliminary Order that merely showing
movement towards a policy goal is not a sufficient standard upon which to approve deferral.1072
Thus, ETI’s statement that deferred accounting will “support” wholesale competition addresses a
standard that the Commission already rejected. Second, Staff argues that ETI failed establish that
deferred accounting is “necessary” to support a competitive wholesale market or that failure to allow
deferred accounting would prevent that goal. In other words, ETI did not show that, absent deferral,
it would not join MISO; thus, ETI did not show how deferral would “ensure” that it joins an RTO.
Therefore, Staff concluded, because ETI failed to prove that deferred accounting is necessary to
carry out any provision of PURA, ETI’s request should be denied.


          In response to these arguments, ETI noted that no party disputed that the Commission may
grant deferred accounting “when it is necessary to carry out a provision of PURA.” It also argues
that Staff and intervenors misinterpreted State v. Public Utility Comm’n of Texas1073 as holding that
deferred accounting is necessary to carry out PURA § 36.051 only when a utility’s financial integrity
is at stake. Although lack of financial integrity is an indication that PURA § 36.051 has not been
carried out, ETI noted that this section contains other express requirements that can be met through
deferred accounting, such as ensuring utilities a reasonable opportunity to recover their costs. ETI
also cited other Commission cases in which it authorized deferred accounting when financial
integrity was not at stake, such as deferral of rate case expenses and merger costs for subsequent
review and recovery.1074 ETI added that deferred accounting would permit the Commission to
review ETI’s transition expenses in a subsequent proceeding, after determining whether ETI’s
transition to MISO is in the public interest. Thus, under ETI’s proposal, there is no risk that ETI
would recover such costs absent a finding that they are reasonable and necessary.



1071
       ETI Initial Brief at 234.
1072
       Docket No. 39741, Preliminary Order at 11.
1073
       883 S.W.2d 190 (Tex. 1994).
1074
       ETI Reply Brief at 95-96.
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          As for Staff and TIEC’s argument that deferred accounting is not necessary to carry out
PURA § 31.001(c), ETI argues that the “necessary” standard is not a “but for” test. In response to
arguments that the proposed deferred accounting will merely further policy objectives of
Section 31.001(c), which the Commission has deemed insufficient to meet the “necessary”
standard,1075 ETI reiterated that the Hammack opinion held that “the Commission’s interpretation of
need must be viewed in light of the legislative directive that the Commission formulate policies
responsive to the needs of the emerging competitive wholesale market,” as well as “overall policy
objectives.”1076 Thus, ETI argues, that it has demonstrated that deferred accounting is necessary to
carry out Section 31.001(c) – i.e., it will “ensure” that the requirements of that provision are carried
out, and in particular ensure that the Legislature’s specific instruction to develop the wholesale
market is carried out.1077


          Although ETI’s proposal for deferred accounting has some practical appeal, the ALJs
conclude that ETI has not shown that it is necessary to carry out a provision of PURA. The ALJs
find that ETI was not required to show that a deferred accounting is necessary to maintain its
financial integrity, as argued by intervenors. In State v. Public Utility Comm’n of Texas,1078 the
Texas Supreme Court held that preserving the financial integrity of a utility was necessary to carry
out a provision of PURA, and thus justified deferred accounting for certain expenses in that case, but
the court did not hold that preserving financial integrity was the sole basis upon which a deferred
accounting could be approved. Likewise, in its Preliminary Order for the present case, the
Commission stated: “This standard [financial integrity] is not appropriate, however, for all
circumstances and the Commission has applied different standards in various circumstances,
although none of these standards or circumstances has been reviewed by any court.”1079 On the
other hand, the ALJs also find that ETI’s contention that deferred accounting of the MISO transition
expenses will help the development of a competitive wholesale electric market, as described in


1075
       Docket No. 39741, Preliminary Order at 7.
1076
     Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.—Austin 2004, pet.
denied).
1077
       ETI Reply Brief at 97-99.
1078
       883 S.W.2d 190 (Tex. 1994).
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PURA § 31.001(c), is not sufficient to authorize deferred accounting. Again, the Commission stated
in the Preliminary Order that “to carry out a provision of PURA” means more than undefined
progress or movement towards a statutory objective.1080


           The Commission made clear that ETI’s burden was not only to show that a provision of
PURA would be carried out by an accounting deferral of the MISO transition expenses, but that the
deferral is necessary to carry out that provision. The Commission added that necessity was a
question of fact that “can only be determined after development of an adequate factual record that
demonstrates the necessity, of whatever degree.”1081 Intervenors argue that Entergy’s efforts to
transfer operational control of the Entergy Operating Companies’ transmission assets to MISO will
proceed with or without the deferred accounting requested by ETI; thus, deferred accounting is not
necessary. Likewise, intervenors argue that ETI’s alternate proposal to recover the transition costs
through base rates shows that deferred accounting is not necessary. ETI, however, asserted that
necessity should not be considered a “but for” requirement. It noted that no provision of PURA
would be impossible to carry out absent a deferral of rate case expenses or merger expenses, yet the
Commission has allowed deferred accounting of such expenses in other cases. ETI also cited the
statement in Hammack v. Public Utility Commission of Texas that “a need . . . is a relative
requirement, ranging from an imperative need to one that is minimal . . . .”1082 Intervenors criticized
ETI’s reliance on the Hammack case because it concerned a transmission line. While that is correct,
the case does make the general point that the question of need is not an absolute “but for” test. This
is also consistent with the Commission’s statement in the Preliminary Order that ETI’s burden was
to demonstrate necessity, “of whatever degree.”


           ETI’s complaint is that its MISO transition expenses will soon increase above the Test Year
amount, from $916,535 for the Test Year to over $5 million per year, but it will not be able to
recover the increased costs through normal Test Year cost-of-service ratemaking principles. Thus,

1079
       Docket No. 39741, Preliminary Order at 9 (Nov. 22, 2011).
1080
       Id. at 11.
1081
       Id. at 8.
1082
     Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.—Austin 2004, pet.
denied).
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although ETI’s financial integrity may not be jeopardized, ETI argues that it nevertheless will not be
able to have a reasonable opportunity to recover its expenses and receive reasonable rates as
required by PURA §§ 36.051 and 36.003(a). Therefore, ETI believes the proposed deferred
accounting is necessary to carry out those provisions of PURA.


          The ALJs find that the essence of ETI’s complaint is that regulatory lag works against it in
this particular situation. But as noted by the court in State v. Public Utility Comm’n of Texas,
regulatory lag is an ordinary element of risk for utilities.1083 One of the characteristics of Test Year
cost-of-service ratemaking is that some expenses upon which rates are based may go up and others
may go down during the time the rates are in effect. Such changes can be corrected in future
ratemaking proceedings, but in this case ETI desires to ensure that it will recover all of its MISO
transition costs. But State v. Public Utility Comm’n of Texas and the Commission’s Preliminary
Order in this case make clear that eliminating the normal effects of regulatory lag by allowing a
deferred accounting should not be undertaken lightly. If ETI’s arguments were taken to their
extreme, a utility could obtain deferred accounting any time it anticipated a post Test Year increase
in a particular expense, under the argument that it must be allowed to recover all of its expenses to
carry out the requirements of PURA §§ 36.051 and 36.003(a). In this case, ETI’s estimated MISO
transition costs will equal about $5.8 million per year. As Mr. Pollock noted, this is only
one percent of ETI’s Test Year operating revenues, which may easily be subsumed in the normal
variation in ETI’s year-to-year expenses. Under these circumstances, ETI has not shown that
granting its requested deferred accounting is necessary to carry out the requirements of PURA
§§ 36.051 and 36.003(a) that it receive just and reasonable rates. Therefore, the ALJs recommend
that the Commission deny ETI’s request for deferred accounting treatment of its MISO transition
expenses to be incurred on or after January 1, 2011.




1083
       883 S.W.2d 190, 196 (Tex. 1994).
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        2. Base Rate Recovery

        As mentioned above, if the Commission denies ETI’s request for deferred accounting, ETI
requested the Commission to include $4 million of MISO transition expense in base rates set in the
present case, based on a three-year amortization of $12 million in total projected expenses.


        Cities disputed the amount of MISO expenses ETI requested in this proposal. Cities witness
Mark Garrett testified that a $4 million annual expense is inconsistent with ETI’s own projected
costs. The Test Year expenses were $916,535, and the actual expenses incurred during January
through November 2011 were only $2.513 million, which annualized would be $2.742 million..
For 2013, ETI projected MISO transition expenses of only $2.587 million, although ETI’s
projected 2012 level of $8.9 million. However, Mr. Garrett added that 2012 is an estimated level
and is not consistent with actual 2011 results. In his opinion, the actual 2011 level of about $2.7
million or the expected 2013 level of about $2.6 million should be the outside range of what the
Commission should use for setting prospective rates. In any event, however, Cities argue that these
projected levels are not sufficiently known and measurable to include for ratemaking purposes.
Cities pointed out that it is unknown whether ETI’s proposed move to MISO will even be approved,
or whether the ETI will even continue to incur costs toward a MISO transition. Therefore, Cities
argues that only the Test Year level of $916,535 should be included in rates, which would result in a
downward adjustment of $3,083,462 to ETI’s request.1084


        TIEC also argues that ETI’s alternative proposal should be rejected. Mr. Pollock complained
that this proposal would allow ETI to recover post Test Year expenses that are not known and
measureable. Mr. Pollock noted that ETI’s own estimate of its share of transition costs has changed.
When ETI filed its request for deferred accounting in Docket No. 39741, it estimated transition costs
of $12 million. Now it estimates costs of $17 million, an increase of over 40 percent. Further,
Mr. Pollock stated, ETI based its share of the estimated transition costs by assuming a 17 percent
responsibility ratio, but ETI’s future responsibility ratios are not known because they are based on
projected growth rates of ETI relative other Entergy Operating Companies. Thus, Mr. Pollock

1084
     Cities Ex. 2 (Garrett Direct) at 61-63 and Ex. MG2.14; Cities Initial Brief at 89-91; Cities Reply Brief
at 112-113.
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concluded that ETI’s share of future MISO transition costs cannot be appropriately measured.1085 In
summary, TIEC argues that the Commission should deny ETI’s request for deferred accounting and
should allow ETI to recover only Test Year MISO transition expenses.1086 Commission Staff made
arguments similar to Cities and TIEC.1087


          In response, ETI argues that the $4 million annual expense requested is known and
measurable. ETI noted that it already incurred over $3.6 million in transition expense in the nine
months since the end of the Test Year,1088 which equates to $4.8 million on an annual basis.
Furthermore, ETI’s expects $17 million in transition expenses to be incurred over three years, which
equates to $5.8 million annually.1089 In ETI’s view, the issue is whether it is sufficiently known that
ETI will incur at least $12 million in transition expense, not whether ETI can predict an exact level
of future expense.1090


          The ALJs recommend that the Commission authorize ETI to include $2.4 million in base
rates set in the present case for MISO transition expense incurred on or after January 2, 2011, based
on a five-year amortization of $12 million in total projected expenses. The primary argument of
intervenors against the adjustment is that the total of $12 million is not a known and measurable
change. However, the ALJs find that ETI’s evidence established that such expenses will total at
least $12 million. It is true that the Test Year expenses were less, but ETI filed its application to
effectuate the transfer to MISO in 2012, so it is clear that those expenses will increase significantly
to levels well above the Test Year amount. It is true that ETI has not established the precise total
amount of MISO transition expenses it will incur, but the ALJs find that those expenses will likely
exceed the $12 million included in ETI’s request. ETI requested that the $12 million total be
amortized over three years, which would produce a $4 million annual cost. However, ETI also


1085
       TIEC Ex. 1 (Pollock Direct) at 49-50.
1086
       TIEC Initial Brief at 97-98; TIEC Reply Brief at 70-71.
1087
       Staff Reply Brief at 65-66.
1088
       ETI Ex. 46 (Considine Rebuttal), Ex. MPC-R-1.
1089
       TIEC Ex. 1 (Pollock Direct) at 48:3-4.
1090
       ETI Initial Brief at 236-239; ETI Reply Brief at 99-100.
SOAH DOCKET NO. XXX-XX-XXXX                  PROPOSAL FOR DECISION                           PAGE 338
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requested to amortize over five years its $263,908 in MISO transition expenses that were incurred
during the 2010 portion of the Test Year ($52,800 per year). If a five-year amortization is
appropriate for those expenses, a five-year amortization would also be appropriate for the post Test
Year MISO transition expenses. Therefore, the ALJs recommend that the Commission authorize
ETI to include in base rates $52,800 in MISO transition expenses for the 2010 portion of the Test
Year expenses, plus $2.4 million for the post Test Year adjustment, for a total of $2,452,800.


B.        TCRF Baseline [Germane to Supplemental Preliminary Order Issue No. 2]

          In its Supplemental Preliminary Order, the Commission found that it would be appropriate to
establish for ETI baseline values for a TCRF and a DCRF, which may be established in future
dockets. ETI’s filing package included worksheets for these baseline values,1091 and ETI attached
revised versions of the worksheets to its initial brief to reflect ETI’s revised depreciation
calculations. The revised version of the transmission worksheet calculated total transmission cost
baseline revenue requirements of $75,074,987-Total Company and $74,997,366-Retail.1092
However, ETI acknowledged that these values may change, depending on the rulings in this case. If
the Commission makes other changes to ETI’s requested costs, ETI proposes filing another revised
TCRF baseline value calculation in the compliance phase of this case, to reflect the final decisions of
the Commission.1093 TIEC, Cities, and Staff also point out that various items in ETI’s calculation
have been contested. Therefore, they also recommend that the baseline values be set during the
compliance phase of this case. The ALJs agree that TCRF baseline values should be set during the
compliance phase of this docket, after the Commission makes final rulings on the various contested
issues that may affect this calculation.


C.        DCRF Baseline [Germane to Supplemental Preliminary Order Issue No. 2]

          As discussed above, the Commission found in its Supplemental Preliminary Order that it
would be appropriate to establish for ETI baseline values for a DCRF, which may be established in a

1091
       ETI Ex. 31 (LeBlanc Direct) at Ex. HGL-5 and HGL-6.
1092
       ETI Initial Brief at 239 and Attachment 1.
1093
       ETI Initial Brief at 239.
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PUC DOCKET NO. 39896


future docket. ETI’s filing package included worksheets for a DCRF baseline value,1094 and ETI
attached a revised version of the worksheet to its initial brief to reflect ETI’s revised depreciation
calculations. The revised version of the distribution worksheet calculated total distribution cost
baseline revenue requirements of $163,560,232-Total Company and $161,537,490-Retail.1095
However, ETI acknowledged that these values may change, depending on the rulings in this case. If
the Commission makes other changes to ETI’s requested costs, ETI proposes filing another revised
DCRF baseline value calculation in the compliance phase of this case, to reflect the final decisions
of the Commission.1096 TIEC, Cities, and Staff also recommend that the baseline values be set
during the compliance phase of this case. The ALJs agree that DCRF baseline values should be set
during the compliance phase of this docket, after the Commission makes final rulings on the various
contested issues that may affect this calculation.


D.        Purchased Power Capacity Cost Baseline [Germane to Supplemental Preliminary
          Order Issue No. 1]

          ETI requested a PPR rider in its application, but the Commission held in its Supplemental
Preliminary Order that the proposed rider should not be considered due to the pending rulemaking
Project No. 39246, which was opened to consider purchased capacity riders. However, the
Commission did add the following issue to the present case: “What is the amount of purchased-
capacity costs that are proposed to be included in Entergy’s base rates?” ETI requested authority to
include $275,809,485 in its PPR rider, but because the Commission excluded the PPR rider from
consideration, this amount would now be included in base rates. ETI acknowledged that this amount
should be revised to correspond with the Commission’s final decision on purchased power capacity
recovery (See Section VII.A.). 1097


          State Agencies noted that ETI’s purchased power request included the following:



1094
       ETI Ex. 31 (LeBlanc Direct) at Ex. HGL-5 and HGL-6.
1095
       ETI Initial Brief at 239 and Attachment 2.
1096
       ETI Initial Brief at 239.
1097
       ETI Initial Brief at 240.
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                  1.       Third-party contracts;
                  2.       Legacy affiliate contracts;
                  3.       Other affiliate contracts; and
                  4.       Reserve Equalization.


The costs for all of these but third-party contracts are determined through various MSS Schedules in
the FERC-approved Entergy System Agreement. Therefore, State Agencies argue that if the
Commission decides to allow purchased capacity cost recovery riders in Project No. 39246, the
baseline costs for ETI should be limited to only the purchased capacity costs associated with
non-affiliate third-party contracts. In State Agencies’ opinion, ETI should not be allowed to pass
through purchased capacity costs associated with legacy and other affiliate contracts or reserve
equalization purchases, because those are not market competitive contracts. Instead, according to
State Agencies, the affiliate contracts and reserve equalization purchases are essentially agreements
to share centralized planned generation capacity resources among Entergy Operating Companies and
to allocate generation costs among those companies. State Agencies also noted that these capacity
payments are determined based on formulae in Service Schedules MSS-1 and MSS-4, included in
the FERC-approved Entergy System Agreement. In other words, these costs are not driven by
market prices and are not subject to market price volatility. Therefore, State Agencies argue that
purchases other than third-party contracts should not be used as a baseline for any rider intended to
address market price volatility and competitive wholesale market pressure for purchased generation
capacities.1098


          Cities agree with the arguments of State Agencies. In addition, Cities stressed that if the
Commission establishes a baseline for purchased power capacity costs, the baseline should reflect
the unit cost of capacity rather than total dollars. Cities witness Nalepa testified that the unit cost
would provide a more accurate measure than total dollars. In Cities’ opinion, if a unit cost finding is
not made in this case, then Commission will be prevented from considering all options in the
rulemaking.



1098
       State Agencies Ex. 2 (Pevoto Direct) at 17.
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          TIEC points out that the notice in Project No. 39246 provided that “[t]he purpose of this
rulemaking project is to address the recovery of purchased power capacity costs considering
generation embedded in base rates, load growth, and the impact of purchased power capacity
recovery on the financial standing of the utility.”1099 Accordingly, TIEC argues that the baseline set
in this proceeding should reflect ETI’s total purchased power and installed capacity costs determined
to be properly included in base rates on a total cost basis and on a per unit ($/MW) basis.1100


          As discussed in Section VII.A., the ALJs find that the appropriate amount for ETI’s
purchased power capacity expense to be included in base rates is $245,432,884. This responds to the
issue included in the Commission’s Supplemental Preliminary Order. This amount includes third-
party contracts, legacy affiliate contracts; other affiliate contracts; and reserve equalization.
Whether the amounts for all contracts should be included in the baseline for a purchased capacity
rider that may be approved in Project No. 39246 is an issue that should be decided in that
proceeding, not in the present case. Therefore, the ALJs make no recommendation on that issue
raised by the intervenors.


                                     XIII.     CONCLUSION

          The ALJs recommend that the Commission implement the findings of the ALJs set forth in
the discussion above by adopting the following proposed findings of fact and conclusions of law in
the Commission’s final order.


       XIV.     PROPOSED FINDINGS OF FACT, CONCLUSIONS OF LAW, AND
                              ORDERING PARAGRAPHS

A.        Findings of Fact

Procedural History

1.        Entergy Texas, Inc. (ETI or the Company) is an investor-owned electric utility with a retail
          service area located in southeastern Texas.

1099
       Project No. 39246, Public Notice (May 10, 2011).
1100
       TIEC Initial Brief at 99.
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2.    ETI serves retail and wholesale electric customers in Texas. As of June 30, 2011, ETI
      served approximately 412,000 Texas retail customers. The Federal Energy Regulatory
      Commission (FERC) regulates ETI’s wholesale electric operations.

3.    On November 28, 2011, ETI filed an application requesting approval of: (1) a proposed
      increase in annual base rate revenues of approximately $111.8 million over adjusted test year
      revenues; (2) a set of proposed tariff schedules presented in the Electric Utility Rate Filing
      Package for Generating Utilities (RFP) accompanying ETI’s application and including new
      riders for recovery of costs related to purchased power capacity and renewable energy credit
      requirements; (3) a request for final reconciliation of ETI’s fuel and purchased power costs
      for the reconciliation period from July 1, 2009 to June 30, 2011; and (4) certain waivers to
      the instructions in RFP Schedule V accompanying ETI’s application.

4.    The 12-month test year employed in ETI’s filing ended on June 30, 2011 (Test Year).

5.    ETI provided notice by publication for four consecutive weeks before the effective date of
      the proposed rate change in newspapers having general circulation in each county of ETI’s
      Texas service territory. ETI also mailed notice of its proposed rate change to all of its
      customers. Additionally, ETI timely served notice of its statement of intent to change rates
      on all municipalities retaining original jurisdiction over its rates and services.

6.    The following parties were granted intervenor status in this docket: Office of Public Utility
      Counsel (OPC); the cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Dayton,
      Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange,
      Pine Forest, Rose City, Pinehurst, Port Arthur, Port Neches, Shenandoah, Silsbee, Sour
      Lake, Splendora, Vidor, and West Orange (Cities), the Kroger Co. (Kroger); State Agencies
      (State Agencies); Texas Industrial Energy Consumers (TIEC); East Texas Electric
      Cooperative, Inc. (ETEC); the United States Department of Energy (DOE); and Wal-Mart
      Stores Texas, LLC, and Sam’s East, Inc. (Wal Mart). The Staff (Staff) of the Public Utility
      Commission of Texas (Commission or PUC) was also a participant in this docket.

7.    On November 29, 2011, the Commission referred this case to the State Office of
      Administrative Hearings (SOAH).

8.    On December 7, 2011, the Commission issued its order requesting briefing on threshold
      legal/policy issues.

9.    On December 19, 2011, the Commission issued its Preliminary Order, identifying 31 issues
      to be addressed in this proceeding.

10.   On December 20, 2011, the Administrative Law Judges (ALJs) issued SOAH Order No. 2,
      which approved an agreement among the parties to establish a June 30, 2012 effective date
      for the Company’s new rates resulting from this case pursuant to certain agreed language and
      consolidate Application of Entergy Texas, Inc. for Authority to Defer Expenses Related to its
      Proposed Transition to Membership in the Midwest Independent System Operator, Docket
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PUC DOCKET NO. 39896


      No. 39741 (pending) into this proceeding. Although it did not agree, Staff did not oppose
      the consolidation.

11.   On January 13, 2012, the ALJs issued SOAH Order No. 4 granting the motions for
      admission pro hac vice filed by Kurt J. Boehm and Jody M. Kyler to appear and participate
      as counsel for Kroger and the motion for admission pro hac vice filed by Rick D.
      Chamberlain to appear and participate as counsel for Wal-Mart.

12.   On January 19, 2012, the Commission issued a Supplemental Preliminary Order identifying
      two additional issues to be addressed in this case and concluding that the Company’s
      proposed purchased power capacity rider should not be addressed in this case and that such
      costs should be recovered through base rates.

13.   ETI timely filed with the Commission petitions for review of the rate ordinances of the
      municipalities exercising original jurisdiction within its service territory. All such appeals
      were consolidated for determination in this proceeding.

14.   On April 4, 2012, the ALJs issued SOAH Order No. 13 severing rate case expense issues
      into Application of Entergy Texas, Inc. for Rate Case Expenses Severed from PUC Docket
      No. 39896, Docket No. 40295 (pending).

15.   On April 13, 2012, ETI adjusted its request for a proposed increase in annual base rate
      revenues to approximately $104.8 million over adjusted Test Year revenues.

16.   The hearing on the merits commenced on April 24 and concluded on May 4, 2012.

17.   Initial post-hearing briefs were filed on May 18 and reply briefs were filed on May 30, 2012.

Rate Base

18.   Capital additions that were closed to ETI’s plant-in-service between July 1, 2009, and June
      30, 2011, are used and useful in providing service to the public and were prudently incurred.

19.   ETI’s proposed Hurricane Rita regulatory asset was an issue resolved by the black-box
      settlement in Application of Entergy Texas, Inc. for Authority to Change Rates and
      Reconcile Fuel Costs, Docket No. 37744 (Dec. 13, 2010).

20.   Accrual of carrying charges on the Hurricane Rita regulatory asset should have ceased when
      Docket No. 37744 concluded because the asset would have then begun earning a rate of
      return as part of rate base.

21.   The appropriate calculation of the Hurricane Rita regulatory asset should begin with the
      amount claimed by ETI in Docket No. 37744, less amortization accruals to the end of the
      Test Year in the present case, and less the amount of additional insurance proceeds received
      by ETI after the conclusion of Docket No. 37744.
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PUC DOCKET NO. 39896


22.   A Test-Year-end balance of $15,175,563 for the Hurricane Rita regulatory asset should
      remain in rate base, applying a five-year amortization rate beginning August 15, 2010.

23.   The Hurricane Rita regulatory asset should not be moved to the storm damage insurance
      reserve.

24.   The Company requested in rate base its Prepaid Pension Assets Balance of $55,973,545,
      which represents the accumulated difference between the Statement of Financial Accounting
      Standards (SFAS) No. 87 calculated pension costs each year and the actual contributions
      made by the Company to the pension fund.

25.   The Prepaid Pension Assets Balance includes $25,311,236 capitalized to construction work
      in progress (CWIP).

26.   It is not necessary to the financial integrity of ETI to include CWIP in rate base, and there
      was insufficient evidence showing that major projects under construction were efficiently
      and prudently managed.

27.   The portion of the Prepaid Pension Assets Balance that is capitalized to CWIP should not be
      included in ETI’s rate base.

28.   The remainder of the Prepaid Pension Assets Balance should be included in ETI’s rate base.

29.   ETI should be permitted to accrue an allowance for funds used during construction on the
      portion of ETI’s Prepaid Pension Assets Balance capitalized to CWIP.

30.   The Financial Accounting Standard Board (FASB) Financial Interpretation No. 48 (FIN 48),
      “Accounting for Uncertainty in Income Taxes,” requires ETI to identify each of its uncertain
      tax positions by evaluating the tax position on its technical merits to determine whether the
      position, and the corresponding deduction, is more-likely-than-not to be sustained by the
      Internal Revenue Service (IRS) if audited.

31.   FIN 48 requires ETI to remove the amount of its uncertain tax positions from its
      Accumulated Deferred Federal Income Tax (ADFIT) balance for financial reporting
      purposes and record it as a potential liability with interest to better reflect the Company’s
      financial condition.

32.   At Test Year-end, ETI had $5,916,461 in FIN 48 liabilities, meaning ETI has, thus far,
      avoided paying to the IRS $5,916,461 in tax dollars (the FIN 48 Liability) in reliance upon
      tax positions that the Company believes will not prevail in the event the positions are
      challenged, via an audit, by the IRS.

33.   ETI has deposited $1,294,683 with the IRS in connection with the FIN 48 Liability.

34.   The IRS may never audit ETI as to its uncertain tax positions creating the FIN 48 Liability.

35.   Even if ETI is audited, ETI might prevail on its uncertain tax positions.
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PUC DOCKET NO. 39896


36.   ETI may never have to pay the IRS the FIN 48 Liability.

37.   Other than the amount of its deposit with the IRS, ETI has current use of the FIN 48 Liability
      funds.

38.   Until actually paid to the IRS, the FIN 48 Liability represents cost-free capital and should be
      deducted from rate base.

39.   The amount of $4,621,778 (representing ETI’s full FIN 48 Liability of $5,916,461 less the
      $1,294,683 cash deposit ETI has made with the IRS for the FIN 48 Liability) should be
      added to ETI’s ADFIT and thus be used to reduce ETI’s rate base.

40.   ETI’s application and proposed tariffs do not include a request for a tracking mechanism or
      rider to collect a return on the FIN 48 Liability.

41.   ETI has not proven that a tracking mechanism or rider to collect a return on FIN 48 Liability
      is necessary.

42.   Investor-owned electric utilities may include a reasonable allowance for cash working
      capital in rate base as determined by a lead-lag study conducted in accordance with the
      Commission’s rules.

43.   Cash working capital represents the amount of working capital, not specifically addressed in
      other rate base items, that is necessary to fund the gap between the time expenditures are
      made and the time corresponding revenues are received.

44.   The lead-lag study conducted by ETI considered the actual operations of ETI, adjusted for
      known and measurable changes, and is consistent with P.U.C. SUBST.
      R. 25.231(c)(2)(B)(iii).

45.   It is reasonable to establish ETI’s cash working capital requirement based on ETI’s lead-lag
      study as updated in Jay Joyce’s rebuttal testimony and on the cost of service approved for
      ETI in this case.

46.   As a result of the black-box settlements in Application of Entergy Gulf States, Inc. for
      Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800 (Nov. 7, 2008)
      and Docket No. 37744, the Commission did not approve ETI’s storm damage expenses since
      1996 and its storm damage reserve balance.

47.   ETI established a prima facie case concerning the prudence of its storm damage expenses
      incurred since 1996.

48.   Adjustments to the storm damage reserve balance proposed by intervenors should be denied.

49.   The Hurricane Rita regulatory asset should not be moved to the storm damage insurance
      reserve.
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50.   ETI’s appropriate Test-Year-end storm reserve balance was negative $59,799,744.

51.   The amount of $9,846,037, representing the value of the average coal inventory maintained
      at ETI’s coal-burning facilities, is reasonable, necessary, and should be included in rate base.

52.   The Spindletop gas storage facility (Spindletop Facility) is used and useful in providing
      reliable and flexible natural gas supplies to ETI’s Sabine Station and Lewis Creek generating
      plants.

53.   The Spindletop Facility is critical to the economic, reliable operation of the Sabine Station
      and Lewis Creek generating plants due to their geographic location in the far western region
      of the Entergy system.

54.   It is reasonable and appropriate to include ETI’s share of the costs to operate the Spindletop
      Facility in rate base.

55.   Staff recommended updating ETI’s balance amounts for short-term assets to the 13-month
      period ending December 2011, which was the most recent information available. Staff’s
      proposed adjustments should be incorporated into the calculation of ETI’s rate base.

56.   The following short-term asset amounts should be included in rate base: prepayments at
      $8,134,351; materials and supplies at $29,285,421; and fuel inventory at $52,693,485.

57.   The amount of $1,127,778, representing costs incurred by ETI when it acquired the
      Spindletop facility, represent actual costs incurred to process and close the acquisition, not
      mere mark-up costs.

58.   ETI’s $1,127,778 in capitalized acquisition costs should be included in rate base because
      ETI incurred these costs in conjunction with the purchase of a viable asset that benefits its
      retail customers.

59.   In its application, ETI capitalized into plant in service accounts some of the incentive
      payments ETI made to its employees. ETI seeks to include those amounts in rate base.

60.   A portion of those capitalized incentive accounts represent payments made by ETI for
      incentive compensation tied to financial goals.

61.   The portion of ETI’s incentive payments that are capitalized and that are financially-based
      should be excluded from ETI’s rate base because the benefits of such payments inure most
      immediately and predominantly to ETI’s shareholders, rather than its electric customers.

62.   The Test Year for ETI’s prior ratemaking proceeding ended on June 30, 2009, and the
      reasonableness of ETI’s capital costs (including capitalized incentive compensation) for that
      prior period was dealt with by the Commission in that proceeding and is not at issue in this
      proceeding.
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63.    In this proceeding, ETI’s capitalized incentive compensation that is financially-based should
       be excluded from rate base, but only for incentive costs that ETI capitalized during the
       period from July 1, 2009 (the end of the prior Test Year) through June 30, 2010 (the
       commencement of the current Test Year).

Rate of Return and Cost of Capital

64.    A return on common equity (ROE) of 9.80 percent will allow ETI a reasonable opportunity
       to earn a reasonable return on its invested capital.

65.    The results of the discounted cash flow model and risk premium approach support a ROE of
       9.80 percent.

66.    A 9.80 percent ROE is consistent with ETI’s business and regulatory risk.

67.    ETI’s proposed 6.74 percent embedded cost of debt is reasonable.

68.    The appropriate capital structure for ETI is 50.08 percent long-term debt and 49.92 percent
       common equity.

69.    A capital structure composed of 50.08 percent debt and 49.92 percent equity is reasonable in
       light of ETI’s business and regulatory risks.

70.    A capital structure composed of 50.08 percent debt and 49.92 percent equity will help ETI
       attract capital from investors.

71.    ETI’s overall rate of return should be set as follows:

                             CAPITAL                                        WEIGHTED AVG
      COMPONENT              STRUCTURE               COST OF CAPITAL        COST OF CAPITAL
      LONG-TERM DEBT         50.08%                  6.74%                  3.38%
      COMMON EQUITY          49.92%                  9.80%                  4.89%
          TOTAL              100.00%                                        8.27%

Operating Expenses


72.    ETI’s Test Year purchased capacity expenses were $245,432,884.

73.    ETI requested an upward adjustment of $30,809,355 as a post-Test Year adjustment to its
       purchased capacity costs. This request was based on ETI’s projections of its purchased
       capacity expenses during a period beginning June 1, 2012 and ending May 31, 2013 (the
       Rate Year).
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74.   ETI’s purchased capacity expense projections were based on estimates of Rate Year
      expenses for: (a) reserve equalization payments under Schedule MSS-1; (b) payments under
      third-party capacity contracts; and (c) payments under affiliate contracts.

75.   ETI’s projection of its Rate Year reserve equalization payments under Schedule MSS-1 is
      based on numerous assumptions, including load growths for ETI and its affiliates, future
      capacity contracts for ETI and its affiliates, and future values of the generation assets of ETI
      and its affiliates.

76.   There is substantial uncertainty with regard to ETI’s projection of its Rate Year reserve
      equalization payments under Schedule MSS-1.

77.   ETI’s projection of its Rate Year third-party capacity contract payments includes numerous
      assumptions, one of which is that every single third-party supplier will perform at the
      maximum level under the contract, even though that assumption is inconsistent with ETI’s
      historical experience.

78.   There is substantial uncertainty with regard to ETI’s projection of its Rate Year third-party
      capacity contract payments.

79.   ETI’s estimates of its Rate Year purchases under affiliate contracts are based on a
      mathematical formula set out in Schedule MSS-4.

80.   The MSS-4 formula for Rate Year affiliate capacity payments reflects that these payments
      will be based on ratios and costs that cannot be determined until the month that the payments
      are to be made.

81.   Over $11 million of ETI’s affiliate transactions were based on a 2013 contract (the EAI
      WBL Contract) that was not signed until April 11, 2012.

82.   There is uncertainty about whether the EAI WBL Contract will ever go into effect.

83.   ETI projects purchasing over 300 megawatts (MW) more in purchased capacity in the Rate
      Year than it purchased in the Test Year.

84.   ETI experienced substantial load growth in the two years before the Test Year, and it
      continues to project similar load growth in the future.

85.   ETI did not meet its burden of proof to demonstrate that a known and measurable adjustment
      of $30,809,355 should be made to its Test Year purchased capacity expenses.

86.   ETI’s purchased capacity expense in this case should be based on the Test Year level of
      $245,432,884.

87.   ETI incurred $1,753,797 of transmission equalization expense during the Test Year.
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88.   ETI proposed an upward adjustment of $8,942,785 for its transmission equalization expense.
      This request was based on ETI’s projections of its transmission equalization expenses
      during the Rate Year.

89.   The transmission equalization expense that ETI will pay in the Rate Year will depend on
      future costs and loads for each of the Entergy operating companies.

90.   ETI’s projection of its Rate Year transmission equalization expenses is uncertain and
      speculative because it depends on a number of variables, including future transmission
      investments, deferred taxes, depreciation reserves, costs of capital, tax rates, operating
      expenses, and loads of each of the Entergy operating companies.

91.   ETI seeks increased transmission equalization expenses for transmission projects that are not
      currently used and useful in providing electric service. ETI’s post-Test Year adjustment is
      based on the assumption that certain planned transmission projects will go into service after
      the Test Year. At the close of the hearing, none of the planned transmission projects had
      been fully completed and some were still in the planning phase.

92.   It is not reasonable for ETI to charge its retail ratepayers for transmission equalization
      expenses related to projects that are not yet in-service.

93.   ETI’s request for a post-Test Year adjustment of $8,942,785 for Rate Year transmission
      equalization expenses should be denied because those expenses are not known and
      measurable. ETI’s post-Test Year adjustment does not with reasonable certainty reflect what
      ETI’s transmission equalization expense will be when rates are in effect.

94.   ETI’s transmission equalization expense in this case should be based on the Test Year level
      of $1,753,797.

95.   P.U.C. SUBST. R. 25.231(c)(2)(ii) states that the reserve for depreciation is the accumulation
      of recognized allocations of original cost, representing the recovery of initial investment
      over the estimated useful life of the asset.

96.   Except in the case of the amortization of the general plant deficiency, the use of the
      remaining life depreciation method to recover differences between theoretical and actual
      depreciation reserves is the most appropriate method and should be continued.

97.   It is reasonable for ETI to calculate depreciation reserve allocations on a straight-line basis
      over the remaining, expected useful life of the item or facility.

98.   Except as described below, the service lives and net salvage rates proposed by the Company
      are reasonable, and these service lives and net salvage rates should be used in calculating
      depreciation rates for the Company’s Production, Transmission, Distribution, and General
      Plant assets.

99.   A 60-year life for Sabine Units 4 and 5 is reasonable for purposes of establishing production
      plant depreciation rates.
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100.   The retirement (actuarial) rate method, rather than the interim retirement method, should be
       used in the development of production plant depreciation rates.

101.   Production plant net salvage is reasonably based on the negative five percent net salvage in
       existing rates.

102.   The net salvage rate of negative 10 percent for ETI’s transmission structures and
       improvements (FERC Account 352) is the most reasonable of those proposed and should be
       adopted.

103.   The net salvage rate of negative 20 percent for ETI’s transmission station equipment (FERC
       Account 353) is the most reasonable of those proposed and should be adopted.

104.   The net salvage rate of negative five percent for ETI’s transmission towers and fixtures
       (FERC Account 354) is the most reasonable of those proposed and should be adopted.

105.   The net salvage rate of negative 30 percent for ETI’s transmission poles and fixtures (FERC
       Account 355) is the most reasonable of those proposed and should be adopted.

106.   The net salvage rate of negative 30 percent for ETI’s transmission overhead conductors and
       devices (FERC Account 356) is the most reasonable of those proposed and should be
       adopted.

107.   A service life of 65 years and a dispersion curve of R3 for ETI’s distribution structures and
       improvements (FERC Account 361) are the most reasonable of those proposed and should be
       approved.

108.   A service life of 40 years and a dispersion curve of R1 for ETI’s distribution poles, towers,
       and fixtures (FERC Account 364) are the most reasonable of those proposed and should be
       approved.

109.   A service life of 39 years and a dispersion curve of R0.5 for ETI’s distribution overhead
       conductors and devices (FERC Account 365) are the most reasonable of those proposed and
       should be approved.

110.   A service life of 35 years and a dispersion curve of R1.5 for ETI’s distribution underground
       conductors and devices (FERC Account 367) are the most reasonable of those proposed and
       should be approved.

111.   A service life of 33 years and a dispersion curve of L0.5 for ETI’s distribution line
       transformers (FERC Account 368) are the most reasonable of those proposed and should be
       approved.

112.   A service life of 26 years and a dispersion curve of L4 for ETI’s distribution overhead
       service (FERC Account 369.1) are the most reasonable of those proposed and should be
       approved.
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113.   The net salvage rate of negative five percent for ETI’s distribution structures and
       improvements (FERC Account 361) is the most reasonable of those proposed and should be
       adopted.

114.   The net salvage rate of negative 10 percent for ETI’s distribution station equipment (FERC
       Account 362) is the most reasonable of those proposed and should be adopted.

115.   The net salvage rate of negative seven percent for ETI’s distribution overhead conductors
       and devices (FERC Account 365) is the most reasonable of those proposed and should be
       adopted.

116.   The net salvage rate of negative five percent for ETI’s distribution line transformers (FERC
       Account 368) is the most reasonable of those proposed and should be adopted.

117.   The net salvage rate of negative 10 percent for ETI’s distribution overhead services (FERC
       Account 369.1) is the most reasonable of those proposed and should be adopted.

118.   The net salvage rate of negative 10 percent for ETI’s distribution underground services
       (FERC Account 369.2) is the most reasonable of those proposed and should be adopted.

119.   A service life of 45 years and a dispersion curve of R2 for ETI’s general structures and
       improvements (FERC Account 390) are the most reasonable of those proposed and should be
       approved.

120.   The net salvage rate of negative 10 percent for ETI’s general structures and improvements
       (FERC Account 390) is the most reasonable of those proposed and should be adopted.

121.   It is reasonable to convert the $21.3 million deficit that has developed over time in the
       reserve for general plant accounts to General Plant Amortization.

122.   A ten-year amortization of the deficit in the reserve for general plant accounts is reasonable
       and should be adopted.

123.   FERC pronouncement AR-15 requires amortization over the same life as recommended
       based on standard life analysis. A standard life analysis determined that a five-year life was
       appropriate for general plant computer equipment (FERC Account 390.2). Therefore, a five
       year amortization for this account is reasonable and should be adopted.

124.   ETI proposed adjustments to its Test Year payroll costs to reflect: (a) changes to employee
       headcount levels at ETI and Entergy Services, Inc. (ESI); and (b) approved wage increases
       set to go into effect after the end of the Test Year.

125.   The proposed payroll adjustments are reasonable but should be updated to reflect the most
       recent available information on headcount levels as proposed by Commission Staff. In
       addition to adjusting payroll expense levels, the more recent headcount numbers should be
       used to adjust the level of payroll tax expense, benefits expense, and savings plan expense.
SOAH DOCKET NO. XXX-XX-XXXX            PROPOSAL FOR DECISION                              PAGE 352
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126.   Staff has appropriately updated headcount levels to the most recent available data but errors
       made by Staff should be corrected. The corrections related to: (a) a double counting of three
       ETI and one ESI employee; (b) inadvertent use of the ETI benefits cost percentage in the
       calculation of ESI benefits costs; (c) an inappropriate reduction of savings plan costs when
       such costs were already included in the benefits percentage adjustments; and (d) corrections
       for full-time equivalents calculations. Staff’s ETI headcount adjustment (AG-7) overstated
       operation and maintenance (O&M) payroll reduction by $224,217, and ESI headcount
       adjustment (AG-7) understated O&M payroll increase by $37,531.

127.   ETI included $14,187,744 for incentive compensation expenses in its cost of service.

128.   The compensation packages that ETI offers its employees include a base payroll amount,
       annual incentive programs, and long-term incentive programs. The majority of the
       compensation is for operational measures, but some is for financial measures.

129.   Incentive compensation that is based on financial measures is of more immediate and
       predominant benefit to shareholders, whereas incentive compensation based on operational
       measures is of more immediate and predominant benefit to ratepayers.

130.   Incentives to achieve operational measures are necessary and reasonable to provide utility
       services but those to achieve financial measures are not.

131.   The $5,376,975 that was paid for long term incentive programs was tied to financial
       measures and, therefore, should not be included in ETI’s cost of service.

132.   Of the amounts that were paid pursuant to the Executive Annual Incentive Plan, $819,062
       was tied to financial measures and, therefore, should be disallowed.

133.   In total, the amount of incentive compensation that should be disallowed is $6,196,037
       because it was related to financial measures that are not reasonable and necessary for the
       provision of electric service.

134.   The amount of incentive compensation that should be included in the cost of service is
       $7,991,707.

135.   To attract and retain highly qualified employees, the Entergy Companies provide a total
       package of compensation and benefits that is equivalent in scope and cost with what other
       comparable companies within the utility business and other industries provide for their
       employees.

136.   When using a benchmark analysis to compare companies’ levels of compensation, it is
       reasonable to view the market level of compensation as a range rather than a precise, single
       point.

137.   ETI’s base pay levels are at market.

138.   ETI’s benefits plan levels are within a reasonable range of market levels.
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139.   ETI’s level of compensation and benefits expense is reasonable and necessary.

140.   ETI provides non-qualified supplemental executive retirement plans for highly compensated
       individuals such as key managerial employees and executives that, because of limitations
       imposed under the Internal Revenue Code, would otherwise not receive retirement benefits
       on their annual compensation over $245,000 per year.

141.   ETI’s non-qualified supplemental executive retirement plans are discretionary costs designed
       to attract, retain, and reward highly compensated employees whose interests are more closely
       aligned with those of the shareholders than the customers.

142.   ETI’s non-qualified executive retirement benefits in the amount of $2,114,931 are not
       reasonable or necessary to provide utility service to the public, not in the public interest, and
       should not be included in ETI’s cost of service.

143.   For the employee market in which ETI operates, most peer companies offer moving
       assistance. Such assistance is expected by employees, and ETI would be placed at a
       competitive disadvantage if it did not offer relocation expenses.

144.   ETI’s relocation expenses were reasonable and necessary.

145.   The Company’s requested operating expenses should be reduced by $40,620 to reflect the
       removal of certain executive prerequisites proposed by Staff.

146.   Staff properly adjusted the Company’s requested interest expense of $68,985 by removing
       $25,938 from FERC account 431 (using the interest rate of 0.12 percent for calendar year
       2012), leaving a recommended interest expense of $43,047.

147.   During the Test Year, ETI’s property tax expense equaled $23,708,829.

148.   ETI requested an upward pro forma adjustment of $2,592,420, to account for the property
       tax expenses ETI estimates it will pay in the Rate Year.

149.   ETI’s requested pro forma adjustment is not reasonable because it is based, in part, upon the
       prediction that ETI’s property tax rate will be increased in 2012, a change that is speculative
       is not known and measurable.

150.   Staff’s recommendation to increase ETI’s Test Year property tax expenses by $1,214,688 is
       based on the historical effective tax rate applied to the known Test Year-end plant in service
       value, consistent with Commission precedent, and based upon known and measurable
       changes.

151.   ETI’s Test Year property tax burden should be adjusted upward by $1,214,688.

152.   Staff recommended reducing ETI’s advertising, dues, and contributions expenses by
       $12,800. The recommendation, which no party contested, should be adopted.
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153.   The final cost of service should reflect changes to cost of service that affect other
       components of the revenue requirement such as the calculation of the Texas state gross
       receipts tax, the local gross receipts tax, the PUC Assessment Tax and the Uncollectible
       Expenses.

154.   The Company’s requested Federal income tax expense is reasonable and necessary.

155.   ETI’s request for $2,019,000 to be included in its cost of service to account for the
       Company’s annual decommissioning expenses associated with River Bend is not reasonable
       because it is not based upon “the most current information reasonably available regarding the
       cost of decommissioning” as required by P.U.C. SUBST. R. 25.231(b)(1)(F)(i).

156.   Based on the most current information reasonably available, the appropriate level of
       decommissioning costs to be included in ETI’s cost of service is $1,126,000.

157.   ETI’s appropriate total annual self-insurance storm damage reserve expense is $8,270,000,
       comprised of an annual accrual of $4,400,000 to provide for average annual expected storm
       losses, plus an annual accrual of $3,870,000 for 20 years to restore the reserve from its
       current deficit.

158.   ETI’s appropriate target self-insurance storm damage reserve is $17,595,000.

159.   ETI should continue recording its annual storm damage reserve accrual until modified by a
       Commission order.

160.   The operating costs of the Spindletop Facility are reasonable and necessary.

161.   The operating costs of the Spindletop Facility paid to PB Energy Storage Services are
       eligible fuel expenses.

Affiliate Transactions

162.   ETI affiliates charged ETI $78,998,777 for services during the Test Year. The majority of
       these O&M expenses—$69,098,041—were charged to ETI by ESI. The remaining affiliate
       services were charged (or credited) to ETI by: Entergy Gulf States Louisiana, L.L.C.;
       Entergy Arkansas, Inc.; Entergy Louisiana, LLC; Entergy Mississippi, Inc.; Entergy
       Operations, Inc.; and non-regulated affiliates.

163.   ESI follows a number of processes to ensure that affiliate charges are reasonable and
       necessary and that ETI and its affiliates are charged the same rate for similar services. These
       processes include: (a) the use of service agreements to define the level of service required
       and the cost of those services; (b) direct billing of affiliate expenses where possible;
       (c) reasonable allocation methodologies for costs that cannot be directly billed; (d) budgeting
       processes and controls to provide budgeted costs that are reasonable and necessary to ensure
       appropriate levels of service to its customers; and (e) oversight controls by ETI’s Affiliate
       Accounting and Allocations Department.
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164.   Affiliates charged expenses to ETI through 1292 project codes during the Test Year.

165.   ETI agreed to remove the following affiliate transactions from its application:
       (1) Project F3PPCASHCT (Contractual Alternative/Cashpo) in the amount of $2,553;
       (2) Project F3PCSPETEI (Entergy-Tulane Energy Institute) in the amount of $14,288; and
       (3) Project F5PPKATRPT (Storm Cost Processing & Review) in the amount of $929.

166.   The $356,151 (which figure includes the $112,531 agreed to by ETI) of costs associated with
       Projects F5PCZUBENQ (Non-Qualified Post Retirement) and F5PPZNQBDU (Non Qual
       Pension/Benf Dom Utl) are costs that are not reasonable and necessary for the provision of
       electric utility service and are not in the public interest.

167.   The $10,279 of costs associated with Project F3PPFXERSP (Evaluated Receipts Settlement)
       are not normally-recurring costs and should not be recoverable.

168.   The $19,714 of costs associated with Project F3PPEASTIN (Willard Eastin et al) are related
       to ESI’s operations, it is more immediately related to Entergy Louisiana, Inc. and Entergy
       New Orleans, Inc. As such, they are not recoverable from Texas ratepayers.

169.   The $171,032 of costs associated with Project F3PPE9981S (Integrated Energy Management
       for ESI) are research and development costs related to energy efficiency programs. As such,
       they should be recovered through the energy efficiency cost recovery factor rather than base
       rates.

170.   Except as noted in the above Findings of Fact Nos. 162-169, all remaining affiliate
       transactions were reasonable and necessary, were allowable, were charged to ETI at a price
       no higher than was charged by the supplying affiliate to other affiliates, and the rate charged
       is a reasonable approximation of the cost of providing service.

Jurisdictional Cost Allocation

171.   ETI has one full or partial requirements wholesale customer – East Texas Electric
       Cooperative, Inc.

172.   ETI proposes that 150 MW be set as the wholesale load for developing retail rates in this
       docket. Using 150 MW to set the wholesale load is reasonable. The 150 MW used to set the
       wholesale load results in a retail production demand allocation factor of 95.3838 percent.

173.   The 12 Coincident Peak (12 CP) allocation method is consistent with the approach used by
       the FERC to allocate between jurisdictions.

174.   Using 12CP methodology to allocate production costs between the wholesale and retail
       jurisdictions is the best method to reflect cost responsibility and is appropriate based on
       ETI’s reliance on capacity purchases.
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Class Cost Allocation and Rate Design

175.   There is no express statutory authorization for ETI’s proposed Renewable Energy Credits
       Rider (REC Rider).

176.   REC Rider constitutes improper piecemeal ratemaking and should be rejected.

177.   ETI’s Test Year expense for renewable energy credits, $623,303, is reasonable and necessary
       and should be included in base rates.

178.   Municipal Franchise Fees (MFF) is a rental expense paid by utilities for the right to use
       public rights-of-way to locate its facilities within municipal limits.

179.   ETI is an integrated utility system. ETI’s facilities located within municipal limits benefit all
       customers, whether the customers are located inside or outside of the municipal limits.

180.   Because all customers benefit from ETI’s rental of municipal right-of-way, municipal
       franchise fees should be charged to all customers in ETI’s service area, regardless of
       geographic location.

181.   It is reasonable and consistent with the Public Utility Regulatory Act (PURA) § 33.008(b)
       that MFF be allocated to each customer class on the basis of in-city kilo-watt hour (kWH)
       sales, without an adjustment for the MFF rate in the municipality in which a given kWH sale
       occurred.

182.   The same reasons for allocating and collecting MFF as set out in Finding of Fact Nos. 178-
       181 also apply to the allocation and collection of Miscellaneous Gross Receipts Taxes. The
       Company’s proposed allocation of these costs to all retail customer classes based on
       customer class revenues relative to total revenues is appropriate.

183.   The Average and Excess (A&E) 4CP method for allocating capacity-related production
       costs, including reserve equalization payments, to the retail classes is a standard
       methodology and the most reasonable methodology.

184.   The A&E 4CP method for allocating transmission costs to the retail classes is standard and
       the most reasonable methodology.

185.   ETI appropriately followed the rate class revenue requirements from its cost of service study
       to allocate costs among customer classes. ETI’s revenue allocation properly sets rates at
       each class’s cost of service.

186.   It is reasonable for ETI to eliminate the service condition for Rate Groups A and C in
       Schedule SHL [Street and Highway Lighting Service] that charges a $50 fee for any
       replacement of a functioning light with a lower-wattage bulb.
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187.   It is appropriate to require ETI to prepare and file, as part of its next base rate case, a study
       regarding the feasibility of instituting LED-based rates and, if the study shows that such rates
       are feasible, ETI should file proposals for LED-based lighting and traffic signal rates it next
       rate case.

188.   An agreement was reached by the parties and approved by the Commission in Docket
       No. 37744 that directed ETI to exclude, in its next rate case, the life-of-contract demand
       ratchet for existing customers in the Large Industrial Power Service (LIPS), Large Industrial
       Power Service-Time of Day, General Service, General Service-Time of Day, Large General
       Service, and Large General Service-Time of Day rate schedules.

189.   ETI’s proposed tariffs in this case did not remove the life-of-contract demand ratchet from
       these rate schedules consistent with the parties’ agreement in Docket No. 37744.

190.   A perpetual billing obligation based on a life-of-contract demand ratchet, as ETI proposed, is
       not reasonable.

191.   ETI’s proposed LIPS and LIPS Time of Day tariffs should be modified to reflect the
       agreement that was adopted by the Commission as just and reasonable in Docket No. 37744.
        Accordingly, these tariffs should be modified as set out in Findings of Fact No. 192-194.

192.   ETI’s Schedule LIPS and LIPS Time of Day § VI should be changed to read:

                       DETERMINATION OF BILLING LOAD

                       The kW of Billing Load will be the greatest of the following:

                       (A) The Customer’s maximum measured 30-minute demand
                       during any 30-minute interval of the current billing month,
                       subject to §§ III, IV and V above; or

                       (B) 60% of Contract Power as defined in § VII; or

                       (C) 2,500 kW.

193.   ETI’s Schedule LIPS and LIPS Time of Day § VII should be changed to read:

                       DETERMINATION OF CONTRACT POWER

                       Unless Company gives customer written notice to the contrary,
                       Contract Power will be defined as below:

                       Contract Power - the highest load established under § VI(A) above
                       during the 12 months ending with the current month. For the initial
                       12 months of Customer’s service under the currently effective
                       contract, the Contract Power shall be the kW specified in the
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                      currently effective contract unless exceeded in any month during the
                      initial 12-month period.

194.   The Large General Service and Large General Service-Time of Day schedules should be
       similarly revised to eliminate ETI’s life-of-contract demand ratchet.

195.   In its proposed rate design for the LIPS class, the Company took a conservative approach
       and increased the current rates by an equal percentage. This minimized customer bill
       impacts while maintaining cost causation principles on a rate class basis.

196.   It is a reasonable move towards cost of service to add a customer charge of $630 to the LIPS
       rate schedule with subsequent increases to be considered in subsequent base rate cases.

197.   It is a reasonable move towards cost of service to slightly decrease the LIPS energy charges
       and increase the demand charges as proposed by Staff witness William B. Abbott.

198.   DOE proposed a new Schedule LIPS rider—Schedule “Schedulable Intermittent Pumping
       Service” (SIPS) for load schedulable at least four weeks in advance, that occurs in the off-
       season (November through April), that can be cancelled at any time, and for load not lasting
       more than 80 hours in a year. For customers whose loads match these SIPS characteristics
       (for example, DOE’s Strategic Petroleum Reserve), the 12-month demand ratchet provision
       of Schedule LIPS does not apply to demands set under the provisions of the SIPS rider. The
       monthly demand set under the SIPS provisions would be applicable for billing purposes only
       in the month in which it occurred. In short, if a customer set a 12-month ratchet demand in
       that month, it would be forgiven and not applicable in the succeeding 12 months.

199.   DOE’s proposed Schedule SIPS is not restricted solely to the DOE and should be adopted. It
       more closely addresses specific customer characteristics and provides for cost-based rates, as
       does another ETI rider applicable to Pipeline Pumping Service.

200.   Standby Maintenance Service (SMS) is available to customers who have their own
       generation equipment and who contract for this service from ETI.

201.   P.U.C. SUBST. R. 25.242(k)(1) provides that rates for sales of standby and maintenance
       power to qualifying facilities should recognize system wide costing principles and should not
       be discriminatory.

202.   It is reasonable to move Schedule SMS toward cost of service by: (a) adding a customer
       charge equivalent to that of the LIPS rate schedule only for SMS customers not purchasing
       supplementary power under another applicable rate; and (b) revising the tariff as follows:
SOAH DOCKET NO. XXX-XX-XXXX              PROPOSAL FOR DECISION                                PAGE 359
PUC DOCKET NO. 39896


                                         Distribution          Transmission
                         Charge           (less than            (69KV and
                                            69KV)                 greater)
                      Billing Load Charge ($/kW):
                      Standby            $2.46                     $0.79
                      Maintenanc
                      e                  $2.27                     $0.60
                      Non-Fuel Energy Charge (¢/kWh)
                      On-Peak          0.881¢                     0.846¢
                      Off-Peak         0.575¢                     0.552¢

203.   ETI’s Additional Facilities Charge Rider (Schedule AFC) prescribes the monthly rental
       charge paid by a customer when ETI installs facilities for that customer that would not
       normally be supplied, such as line extensions, transformers, or dual feeds.

204.   ETI existing Schedule AFC provides two pricing options. Option A is a monthly charge.
       Option B, which applies when a customer elects to amortize the directly-assigned facilities
       over a shorter term ranging from one to ten years, has a variable monthly charge. There is
       also a term charge that applies after the facility has been fully depreciated.

205.   It is reasonable and cost-based to reduce the Schedule AFC Option A rate to 1.20 percent per
       month of the installed cost of all facilities included in the agreement for additional facilities.

206.   It is reasonable and cost-based to reduce the Schedule AFC Option B monthly rate and the
       Post Term Recovery Charge as follows:


       Selected Recovery Term Recovery Term Charge               Post Recovery Term Charge
                    1                        10.88%                          0.35%
                    2                        5.39%                           0.35%
                    3                        3.92%                           0.35%
                    4                        3.20%                           0.35%
                    5                        2.76%                           0.35%
                    6                        2.48%                           0.35%
                    7                        2.28%                           0.35%
                    8                        2.14%                           0.35%
                    9                        1.97%                           0.35%
                   10                        1.94%                           0.35%


207.   The revisions in the above Findings of Fact to Schedule AFC rates reasonably reflect the
       costs of running, operating, and maintaining the directly-assigned facilities.
SOAH DOCKET NO. XXX-XX-XXXX             PROPOSAL FOR DECISION                               PAGE 360
PUC DOCKET NO. 39896


208.   It is reasonable to modify the Large General Service rate schedule by increasing the demand
       charge from $10.25 to $12.81; decreasing the energy charge from $.01023 to $.00513; and
       maintaining the customer charge at $425.05.

209.   Staff’s proposed change to the General Service (GS) rate schedule to gradually move GS
       customers towards their cost of service by recommending a decrease in the customer charge
       from the current rate of $41.09 to $39.91, and a decrease in the energy charges is reasonable
       and should be adopted.

210.   ETI’s Residential Service (RS) rate schedule is composed of two elements: a customer
       charge of $5 per month and a consumption-based energy charge. The Energy charge is a
       fixed rate of 5.802ȼ per kWh from May through October (Summer). In the months
       November through April (Winter), the rates are structured as a declining block, in which the
       price of each unit is reduced after a defined level of usage.

211.   ETI’s Schedule RS declining block rate structure is contrary to energy efficiency efforts and
       the Legislature’s goal of reducing both energy demand and energy consumption in Texas, as
       stated in PURA § 39.905.

212.   Schedule RS winter block rates should be modified consistent with the goal set out in PURA
       § 39.905, with the initial phase-in of a 20 percent reduction in the block differential proposed
       by ETI and subsequent reductions should be reviewed for consideration at the occurrence of
       each rate case filing.

213.   Other elements of Schedule RS are just and reasonable.

Fuel Reconciliation

214.   ETI incurred $616,248,686 in natural-gas expenses during the Reconciliation Period, which
       is from July 2009 through June 2011.

215.   ETI purchased natural gas in the monthly and daily markets and pursuant to a long-term
       contract with Enbridge Inc. pipeline. ETI also transported gas on its own account and
       negotiated operational balancing agreements with various pipeline companies.

216.   ETI employed a diversified portfolio of gas supply and transportation agreements to meet its
       natural-gas requirements, and ETI prudently managed its gas-supply contracts.

217.   ETI’s natural gas expenses were reasonable and necessary expenses incurred to provide
       reliable electric service to retail customers.

218.   ETI incurred $90,821,317 in coal expenses during the Reconciliation Period.
SOAH DOCKET NO. XXX-XX-XXXX           PROPOSAL FOR DECISION                             PAGE 361
PUC DOCKET NO. 39896


219.   ETI prudently managed its coal and coal-related contracts during the Reconciliation Period.

220.   ETI monitored and audited coal invoices from Louisiana Generating, LLC for coal burned at
       the Big Cajun II, Unit 3 facility.

221.   ETI’s coal expenses were reasonable and necessary expenses incurred to provide reliable
       electric service to retail customers.

222.   ETI incurred $990,041,434 in purchased-energy expenses during the Reconciliation Period.

223.   The Entergy System’s planning and procurement processes for purchased power produced a
       reasonable mix of purchased resources at a reasonable price.

224.   During the Reconciliation Period, ETI took advantage of opportunities in the fuel and
       purchased-power markets to reduce costs and to mitigate against price volatility.

225.   ETI’s purchased-energy expenses were reasonable and necessary expenses incurred to
       provide reliable electric service to retail customers.

226.   ETI provided sufficient contemporaneous documentation to support the reasonableness of its
       purchased-power planning and procurement processes and its actual power purchases during
       the Reconciliation Period.

227.   The Entergy system sold power off system when the revenues were expected to be more than
       the incremental cost of supplying generation for the sale, subject to maintaining adequate
       reserves.

228.   The System Agreement is the tariff approved by the FERC that provides the basis for the
       operation and planning of the Entergy system, including the six Operating Companies. The
       System Agreement governs the wholesale-power transactions among the Operating
       Companies by providing for joint operation and establishing the bases for equalization
       among the Operating Companies, including the costs associated with the construction,
       ownership, and operation of the Entergy system facilities.

229.   Under the terms of the Entergy System Agreement, ETI was allocated its share of revenues
       and expenses from off-system sales.

230.   During the Reconciliation Period, ETI recorded off-system sales revenue in the amount of
       $376,671,969 in FERC Account 447 and credited 100 percent of off-system sales revenues
       and margins from off-system sales to eligible fuel expenses.
SOAH DOCKET NO. XXX-XX-XXXX             PROPOSAL FOR DECISION                               PAGE 362
PUC DOCKET NO. 39896


231.   ETI properly recorded revenues from off-system sales and credited those revenues to eligible
       fuel costs.

232.   The Entergy system consists of six Operating Companies, including ETI, which are planned
       and operated as a single, integrated electric system under the terms of the System
       Agreement.

233.   Service Schedule MSS-1 of the System Agreement determines how the capability and
       ownership costs of reserves for the Entergy system are equalized among the Operating
       Companies. These inter-system “reserve equalization” payments are the result of a formula
       rate related to the Entergy system’s reserve capability that is applied on a monthly basis.

234.   Reserve capability under Service Schedule MSS-1 is capability in excess of the Entergy
       system’s actual or planned load built or acquired to ensure the reliable, efficient operation of
       the electric system.

235.   By approving Service Schedule MSS-1, the FERC has approved the method by which the
       Operating Companies share the cost of maintaining sufficient reserves to provide reliability
       for the Entergy system as a whole.

236.   Service Schedule MSS-3 of the System Agreement determines the pricing and exchange of
       energy among the Operating Companies. By approving Service Schedule MSS-3, the FERC
       has approved the method by which the Operating Companies are reimbursed for energy sold
       to the exchange energy pool and how that energy is purchased.

237.   Service Schedule MSS-4 of the System Agreement sets forth the method for determining the
       payment for unit power purchases between Operating Companies. By approving Service
       Schedule MSS-4, the FERC has approved the methodology for pricing Inter-Operating
       Company unit power purchases.

238.   The Entergy system is planned using multi-year, annual, seasonal, monthly, and next-day
       horizons. Once the planning process has identified the most economical resources that can
       be used to reliably meet the aggregate Entergy system demand, the next step is to procure the
       fuel necessary to operate the generating units as planned and acquire wholesale power from
       the market.

239.   Once resources are procured to meet forecasted load, the Entergy system is operated during
       the current day using all the resources available to meet the total Entergy system demand.

240.   After current-day operation, the System Agreement prescribes an accounting protocol to bill
       the costs of operating the system to the individual Operating Companies. This protocol is
       implemented via the Intra-System Bill (ISB) to each Operating Company on a monthly basis.
SOAH DOCKET NO. XXX-XX-XXXX            PROPOSAL FOR DECISION                             PAGE 363
PUC DOCKET NO. 39896


241.   ETI purchased power from affiliated Operating Companies per the terms of Service
       Schedule MSS-3 of the System Agreement. The payments made under Schedule MSS-3 to
       affiliated Operating Companies are reasonable and necessary, and the FERC has approved
       the pricing formula and the obligation to purchase the energy. ETI pays the same price per
       megawatt hour for energy under Service Schedule MSS-3 as does any other Operating
       Company purchasing energy under Service Schedule MSS-3 during the same hour.

242.   The Spindletop Facility is used primarily to ensure gas-supply reliability and guard against
       gas-supply curtailments that can occur as a result of extreme weather or other unusual
       events.

243.   The Spindletop Facility provides a secondary benefit of flexibility in gas supply. ETI can
       back down gas-fired generation to take advantage of more economical wholesale power, or
       use gas from storage to supplement gas-fired generation when load increases during the day
       and thereby avoid more expensive intra-day gas purchases.

244.   ETI’s customers received benefits from the Spindletop Facility during the Reconciliation
       Period through reliable gas supplies and ETI’s monthly and daily storage activity.

245.   ETI prudently managed the Spindletop Facility to provide reliability and flexibility of gas
       supply for the benefit of customers.

246.   ETI proposed new loss factors, based on a December 2010 line loss study, to be applied for
       the purpose of allocating its costs to its wholesale customers and retail customer classes.

247.   ETI’s proposed loss factors are reasonable and shall be implemented on a prospective basis
       as a result of this final order.

248.   ETI seeks a special-circumstances exception to recover $99,715 resulting from the FERC’s
       reallocation of rough production equalization costs in FERC Order No. 720-A, and to treat
       such costs as eligible fuel expense.

249.   Special circumstances exist and it is appropriate for recovery of the rough production cost
       equalization costs reallocated to ETI as a result of the FERC’s decision in Order No. 720-A.

Other Issues

250.   A deferred accounting of ETI’s Midwest Independent Transmission System Operator
       (MISO) transition expenses is not necessary to carry out any requirement of PURA.
SOAH DOCKET NO. XXX-XX-XXXX             PROPOSAL FOR DECISION                               PAGE 364
PUC DOCKET NO. 39896


251.   ETI should include $2.4 million in base rates for MISO transition expense incurred on or
       after January 2, 2011, based on a five-year amortization of $12 million in total projected
       expenses.

252.   ETI should include an additional $52,800 in base rates for MISO transition expenses
       incurred during the 2010 portion of the Test Year, based on a five-year amortization of
       $263,908 in such expenses.

253.   Transmission Cost Recovery Factor baseline values should be set during the compliance
       phase of this docket, after the Commission makes final rulings on the various contested
       issues that may affect this calculation.

254.   Distribution Cost Recovery Factor baseline values should be set during the compliance phase
       of this docket, after the Commission makes final rulings on the various contested issues that
       may affect this calculation.

255.   The appropriate amount for ETI’s purchased power capacity expense to be included in base
       rates is $245,432,884.

256.    The amount of ETI’s purchased power capacity expense includes third-party contracts,
       legacy affiliate contracts, other affiliate contracts, and reserve equalization. Whether the
       amounts for all contracts should be included in the baseline for a purchased capacity rider
       that may be approved in Project No. 39246 is an issue that should be decided in that project.

B.     Conclusions of Law

1.     ETI is a “public utility” as that term is defined in PURA § 11.004(1) and an “electric utility”
       as that term is defined in PURA § 31.002(6).

2.     The Commission exercises regulatory authority over ETI and jurisdiction over the subject
       matter of this application pursuant to PURA §§ 14.001, 32.001, 32.101, 33.002, 33.051,
       36.101–.111, and 36.203.

3.     SOAH has jurisdiction over matters related to the conduct of the hearing and the preparation
       of a proposal for decision in this docket, pursuant to PURA § 14.053 and TEX. GOV’T CODE
       ANN. § 2003.049.

4.     This docket was processed in accordance with the requirements of PURA and the Texas
       Administrative Procedure Act, TEX. GOV’T CODE ANN. Chapter 2001.

5.     ETI provided notice of its application in compliance with PURA § 36.103, P.U.C. PROC.
       R. 22.51(a), and P.U.C. SUBST. R. 25.235(b)(1)-(3).
SOAH DOCKET NO. XXX-XX-XXXX           PROPOSAL FOR DECISION                              PAGE 365
PUC DOCKET NO. 39896


6.    Pursuant to PURA § 33.001, each municipality in ETI’s service area that has not ceded
      jurisdiction to the Commission has jurisdiction over the Company’s application, which seeks
      to change rates for distribution services within each municipality.

7.    Pursuant to PURA § 33.051, the Commission has jurisdiction over an appeal from a
      municipality’s rate proceeding.

8.    ETI has the burden of proving that the rate change it is requesting is just and reasonable
      pursuant to PURA § 36.006.

9.    In compliance with PURA § 36.051, ETI’s overall revenues approved in this proceeding
      permit ETI a reasonable opportunity to earn a reasonable return on its invested capital used
      and useful in providing service to the public in excess of its reasonable and necessary
      operating expenses.

10.   Consistent with PURA § 36.053, the rates approved in this proceeding are based on original
      cost, less depreciation, of property used and useful to ETI in providing service.

11.   The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059 and
      P.U.C. SUBST. R. 25.231(c)(2)(C)(i).

12.   Including the cash working capital approved in this proceeding in ETI’s rate base is
      consistent with P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV), which allows a reasonable
      allowance for cash working capital to be included in rate base.

13.   The ROE and overall rate of return authorized in this proceeding are consistent with the
      requirements of PURA §§ 36.051 and 36.052.

14.   The affiliate expenses approved in this proceeding and included in ETI’s rates meet the
      affiliate payment standards articulated in PURA §§ 36.051, 36.058, and Railroad
      Commission of Texas v. Rio Grande Valley Gas Co., 683 S.W.2d 783 (Tex. App.—Austin
      1984, no writ).

15.   The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059 and
      P.U.C. SUBST. R. 25.231(c)(2)(C)(i).

16.   Pursuant to P.U.C. SUBST. R. 25.231(b)(1)(F), the decommissioning expense approved in
      this case is based on the most current information reasonably available regarding the cost of
      decommissioning, the balance of funds in the decommissioning trust, anticipated escalation
      rates, the anticipated return on the funds in the decommissioning trust, and other relevant
      factors.
SOAH DOCKET NO. XXX-XX-XXXX             PROPOSAL FOR DECISION                               PAGE 366
PUC DOCKET NO. 39896


17.    ETI has demonstrated that its eligible fuel expenses during the Reconciliation Period were
       reasonable and necessary expenses incurred to provide reliable electric service to retail
       customers as required by P.U.C. SUBST. R. 25.236(d)(1)(A). ETI has properly accounted for
       the amount of fuel-related revenues collected pursuant to the fuel factor during the
       Reconciliation Period as required by P.U.C. SUBST. R. 25.236(d)(1)(C).

18.    ETI prudently managed the dispatch, operations, and maintenance of its fossil plants during
       the Reconciliation Period.

19.    The Reconciliation Period level operating and maintenance expenses for the Spindletop
       Facility are eligible fuel expenses pursuant to P.U.C. SUBST. R. 25.236(a).

20.    Special circumstances are warranted pursuant to P.U.C. SUBST. R. 25.236(a)(6) to recover
       rough production equalization payments reallocated to ETI by the FERC.

21.    ETI’s rates, as approved in this proceeding, are just and reasonable in accordance with
       PURA § 36.003.

C.     Proposed Ordering Paragraphs

       In accordance with these findings of fact and conclusions of law, the Commission issues the
following orders:


1.     The Proposal for Decision prepared by the SOAH ALJs is adopted to the extent consistent
       with this Order.

2.     ETI’s application is granted to the extent consistent with this Order.

3.     ETI shall file tariffs consistent with this Order within 20 days of the date of this Order. No
       later than ten days after the date of the tariff filings, Staff shall file its comments
       recommending approval, modification, or rejection of the individual sheets of the tariff
       proposal. Responses to the Staff’s recommendation shall be filed no later than 15 days after
       the filing of the tariff. The Commission shall by letter approve, modify, or reject each tariff
       sheet, effective the date of the letter.

4.     The tariff sheets shall be deemed approved and shall be become effective on the expiration
       of 20 days from the date of filing, in the absence of written notification of modification or
       rejection by the Commission. If any sheets are modified or rejected, ETI shall file proposed
       revisions of those sheets in accordance with the Commission’s letter within ten days of the
       date of that letter, and the review procedure set out above shall apply to the revised sheets.
SOAH DOCKET NO. XXX-XX-XXXX             PROPOSAL FOR DECISION                                PAGE 367
PUC DOCKET NO. 39896


5.    Copies of all tariff-related filings shall be served on all parties of record.

6.    ETI shall prepare and file as part of its next base rate case a study regarding the feasibility of
      instituting LED-based rates and, if the study shows that such rates are feasible, ETI should
      file proposals for LED-based lighting and traffic signal rates in that case. If ETI has LED
      lighting customers taking service, the study shall include detailed information regarding
      differences in the cost of serving LED and non-LED lighting customers. ETI shall provide
      the results of this study to Cities and interested parties as soon as practicable but no later
      than the filing of its next rate case.




7.    All other motions, requests for entry of specific findings of fact and conclusions of law, and
      any other requests for general or specific relief, if not expressly granted, are denied.


     SIGNED July 6, 2012.
                  APPENDIX B

Commission's Order on Rehearing in Docket No. 39896
                                       PUC DOCKET NO. 39896
                                    SOAH DOCKET NO. XXX-XX-XXXX


APPLICATION OF ENTERGY TEXAS,                             §          PUBLIC UTILITY COMMISSION
INC. FOR AUTHORITY TO CHANGE                              §
RATES, RECONCILE FUEL COSTS,                              §                  OF TEXAS
AND OBTAIN DEFERRED                                       §
ACCOUNTING TREATMENT                                      §


                                         ORDER ON REHEARING


       This Order addresses the application of Entergy Texas, Inc. for authority to change rates,
reconcile fuel costs, and defer costs for the transition to the Midwest Independent System
Operator (MISO). In its application, Entergy requested approval of an increase in annual base-
rate revenues of approximately $111.8 million (later lowered to $104.8 million), proposed tariff
schedules, including new riders to recover costs related to purchased-power capacity and
renewable-energy credit requirements, requested final reconciliation of its fuel costs, and
requested waivers to the rate-filing package requirements.

       On July 6, 2012, the State Office of Administrative Hearings (SOAH) administrative law
judges (ALJs) issued a proposal for decision in which they recommended an overall rate increase
for Entergy of $28.3 million resulting in a total revenue requirement of approximately $781
million. The ALJs also recommended approving total fuel costs of approximately $1.3 billion.
The ALJs did not recommend approving the renewable-energy credit rider and the Commission
earlier removed the purchased-power capacity rider as an issue to be addressed in this docket.1
On August 8, 2012, the ALJs filed corrections to the proposal for decision based on the
exceptions and replies of the parties.2 Except as discussed in this Order, the Commission adopts
the proposal for decision, as corrected, including findings of fact and conclusions of law.

       Parties filed motions for rehearing on September 25 and October 4, 2012 and filed replies
to the motions for rehearing on October 15, 2012. The Commission considered the motions for


       1
           Supplemental Preliminary Order at 2, 3 (Jan. 19, 2012).
       2
           Letter from SOAH judges to PUC (Aug. 8, 2012).
PUC Docket No. 39896                                 Order on Rehearing                        Page 2 of 44
SOAH Docket No. XXX-XX-XXXX


rehearing at the October 25, 2012 open meeting. The Commission granted Commission Staff’s
motion for rehearing that requested technical corrections to reflect the rates that resulted from the
Commission Staff number-running memo that was filed on August 28, 2012. The Commission
modifies findings of fact 205, 206, 208, and 210 as requested by Commission Staff and attaches
Commission schedules I through V to reflects its decisions. The Commission granted the
Department of Energy’s motion for rehearing requesting that finding of fact 198 be modified to
reflect the applicable off-season for the schedulable intermittent pumping service. Finding of
fact 198 is modified to reflect that the off-season is October through May. In its motion for
rehearing, Entergy noted that findings of fact 17B and 17D should be modified to more
accurately reflect the procedural history. The Commission modifies findings of fact 17B and
17D to state that Entergy agreed to extend time to provide the Commission sufficient time to
consider the issues in this proceeding on two occasions—at the July 27 and August 30, 2012
open meetings.


                                                  I. Discussion

                                     A. Prepaid Pension Asset Balance
        Entergy included in rate base an approximately $56 million item named Unfunded
Pension.3 This amount represents the accumulated difference between the annual pension costs
calculated in accordance with the Statement of Financial Accounting Standards (SFAS) No. 87
and the actual contributions made by Entergy to the pension fund—Entergy contributed nearly
$56 million more to its pension fund than the minimum required by SFAS No. 87.4

        In Docket No. 33309, the Commission allowed a pension prepayment asset, excluding
the portion of the asset that is capitalized to construction work in progress (CWIP), less accrued
deferred federal income taxes (ADFIT) to be included in rate base.5 For the excluded portion,
the Commission allowed the accrual of an allowance for funds used during construction



        3
            Proposal for Decision at 23 (July 6, 2012) (PFD).
        4
            PFD at 23-24.
        5
         Application of AEP Texas Central Company for Authority to Change Rates, Docket No. 33309, Order on
Rehearing (March 4, 2008).
PUC Docket No. 39896                              Order on Rehearing                                Page 3 of 44
SOAH Docket No. XXX-XX-XXXX


(AFUDC).6 The ALJs concluded that this approach was sound and should be followed in this
case.7 Thus, the ALJs recommended that the CWIP-related portion of Entergy’s prepaid pension
asset ($25,311,236) should be excluded from the asset and should accrue AFUDC.8 However,
the ALJs did not address ADFIT.

        The Commission agrees that the CWIP-related portion of Entergy’s pension asset should
be excluded from the asset and that this excluded portion should accrue AFUDC. However, the
Commission also finds that the impact of this exclusion on Entergy’s ADFIT should be reflected.
When items are excluded from rate base, the related ADFIT should also be excluded. The
adjusted ADFIT for the prepaid pension asset remaining in Entergy’s rate base should be reduced
by $8,858,933, the deferred taxes related to the excluded $25 million. The Commission adds
new finding of fact 28A to reflect this modification to Entergy’s ADFIT.


                                                 B. FIN 48
        The Financial Accounting Standards Board’s Interpretation No. 48 (FIN 48) prescribes
the way in which a company must analyze, quantify, and disclose the potential consequences of
tax positions that the company has taken that are legally uncertain. Entergy reported that its
uncertain tax positions totaled $5,916,461. FIN 48 requires that this amount be recorded on
Entergy’s balance sheet as a tax liability. Entergy also reported that it made a cash deposit with
the IRS in the amount of $1,294,683 associated with its FIN 48 liability.9

        The ALJs concluded that Entergy’s FIN 48 liability should be included in its ADFIT
balance, but the amount of the cash deposit made by Entergy to the IRS attributable to Entergy’s
FIN 48 liability should not be included in Entergy’s ADFIT balance. Accordingly, the ALJs
recommended that $4,621,778 (Entergy’s FIN 48 liability of $5,916,461 less the $1,294,683 cash
deposit Entergy has already made with the IRS) be added to Entergy’s ADFIT balance and thus




        6
          Remand of Docket No. 33309 (Application of AEP Texas Central Company for Authority to Change
Rates), Docket No. 38772, Order on Remand (Jan. 20, 2011).
        7
            PFD at 26.
        8
            Id. at 24-26.
        9
          PFD at 26-27 (citing Rebuttal Testimony of Roberts, Entergy Ex. 64 at 6), 29 (citing Rebuttal Testimony
of Roberts, Entergy Ex. 64 at 8).
PUC Docket No. 39896                           Order on Rehearing                             Page 4 of 44
SOAH Docket No. XXX-XX-XXXX


be used to offset Entergy’s rate base.10 The ALJs did not recommend the addition of a deferred-
tax-account rider because no party expressly advocated the addition of such a rider.11

        The Commission adopts the proposal for decision regarding the adjustment to Entergy’s
ADFIT for the amount attributable to Entergy’s FIN 48 liability. However, the Commission also
follows its precedent regarding the creation of a deferred-tax-account tracker and modifies the
proposal for decision on this point. In CenterPoint’s Electric Delivery Company’s last rate case,
Docket No. 38339,12 the Commission found that tax schedule UTP—on which companies must
describe, list, and rank each uncertain tax position—would provide the IRS auditors sufficient
information to quickly determine which uncertain tax positions are of a magnitude worth
investigating and that an IRS audit would be more likely to occur on some uncertain tax
positions. If an IRS audit of a FIN 48 uncertain tax position results in an unfavorable outcome,
the utility would not be able to earn a return on the amount paid to the IRS until the next rate
case.

        Accordingly, the Commission authorizes Entergy to establish a rider to track unfavorable
FIN-48 rulings by the IRS. The rider will also allow Entergy to recover on a prospective basis
an after-tax return of 8.27% on the amounts paid to the IRS that result from an unfavorable FIN-
48 unfavorable-tax-position audit. The return will be applied prospectively to FIN-48 amounts
disallowed by an IRS audit after such amounts are actually paid to the federal government. If
Entergy subsequently prevails in an appeal of an unfavorable FIN-48 unfavorable-tax-position
decision by the IRS, then any amounts collected under rider related to that overturned decision
shall be credited back to ratepayers.

        The Commission adds new finding of fact 40A and deletes finding of fact 41 consistent
with its decision to authorize the deferred-tax-account tracker.




        10
             PFD at 29.
        11
             Id. at 29.
        12
           Application of CenterPoint Electric Delivery Company, LLC for Authority to Change Rates, Docket
No. 38339, Order on Rehearing at 3-4 (June 23, 2011).
PUC Docket No. 39896                                 Order on Rehearing                                  Page 5 of 44
SOAH Docket No. XXX-XX-XXXX


                                 C. Capitalized Incentive Compensation
       Entergy capitalized into plant-in-service accounts some of the incentive payments made
to employees and sought to include those amounts in rate base. The ALJs determined that
Entergy should not be able to recover its financially based incentive-compensation costs.13
Therefore, the portion of Entergy’s incentive-compensation costs capitalized during the period
July 1, 2009 through June 30, 2010 that were financially based was excluded from Entergy’s rate
base. The ALJs also determined that the actual percentages should be used to determine the
amount that is financially based.14

       In discussing Entergy’s incentive compensation as a component of operating expenses,
the ALJs adopted the method advocated by Texas Industrial Energy Consumers (TIEC) for
calculating the amount of the financially based incentive costs. This method uses the actual
percentage reductions applicable to each of the annual incentive programs that included a
component of financially-based costs.15

       In its exceptions regarding capitalized incentive compensation, Entergy advocated for the
use of TIEC’s methodology to also calculate the amount of capitalized incentive compensation
that is financially based. Entergy also noted that the amount of the disallowance reflected in the
schedules, $1,333,352, was calculated using a disallowance factor that included incentive
compensation tied to cost-control measures, which the ALJs found to be recoverable in the
operating-cost incentive-compensation calculation.16 When the TIEC methodology is applied to
the capitalized incentive-compensation costs in rate base, the net result under TIEC’s
methodology is that only $335,752.96 should be disallowed from capital costs.17

       The Commission agrees that capitalized incentive compensation that is financially based
should be excluded from rate base and that the exclusion only applies to incentive costs that
Entergy capitalized during the period from July 1, 2009 through June 30, 2010. However, the
Commission finds that a consistent methodology should be used to calculate the amount to be


       13
            PFD at 171.
       14
            Id. at 72.
       15
            Id. at 174; see also Entergy’s Exceptions to the Proposal for Decision at 25-26 (July 23, 2012).
       16
            Entergy’s Exceptions to the Proposal for Decision at 25-26.
       17
            Id. at 25-26.
PUC Docket No. 39896                           Order on Rehearing                      Page 6 of 44
SOAH Docket No. XXX-XX-XXXX


excluded and therefore that TIEC’s methodology should also be used for calculating the amount
of capitalized financially based incentive-compensation costs that should be excluded from rate
base. Accordingly, the total amount of capitalized incentive-compensation costs that should be
disallowed from rate base is $335,752.96.          Finding of fact 61 is modified to reflect this
determination.

       As noted by Commission Staff, this disallowance to plant-in-service alters the expense
for ad valorem taxes. Accounting for this disallowance, the appropriate expense amount for ad
valorem taxes is $24,921,022,18 an adjustment of $1,222,106 to Entergy’s test year amount.
Finding of fact 151 is modified to reflect this adjustment to property taxes.


                               D. Rate of Return and Cost of Capital
       The ALJs found the proper range of an acceptable return on equity for Entergy would be
from 9.3 percent to 10.0 percent.19 The mid-point of the range is 9.65 percent. The ALJs found
that the effect of unsettled economic conditions facing utilities on the appropriate return on
equity should be taken into account and that the effect would be to move the ultimate return on
equity towards the upper limits of the range that was determined to be reasonable.20 The ALJs
found that the reasonable adjustment would be 15 basis points, moving the reasonable return on
equity to 9.80 percent.21

       The Commission must establish a reasonable return for a utility and must consider
applicable factors.22 The Commission disagrees with the ALJs that a utility’s return on equity
should be determined using an adder to reflect unsettled economic conditions facing utilities.
The Commission agrees with the ALJs, however, that a return on equity of 9.80 percent will
allow Entergy a reasonable opportunity to earn a reasonable return on its invested capital, but
finds this rate appropriate independent of the 15-point adder recommended by the ALJs. A
return on equity of 9.80 percent is within the range of an acceptable return on equity found by


       18
            Commission Number-Run Memorandum at 2 (Aug. 28, 2012).
       19
            PFD at 94.
       20
            Id.
       21
            Id. at 94.
       22
            PURA §§ 36.051, .052.
PUC Docket No. 39896                                 Order on Rehearing                Page 7 of 44
SOAH Docket No. XXX-XX-XXXX


the ALJs.          Accordingly, the Commission adds new finding of fact 65A to reflect the
Commission’s decision on this point.


                                  E. Purchased-Power Capacity Expense
        The ALJs rejected Entergy’s request to recover $31 million more in purchased-power
capacity costs than its actual test-year expenses because Entergy had failed to prove that the
adjustment was known and measurable,23 and because the request violated the matching
principle.24       Consequently, the ALJs recommended that Entergy’s test-year expenses of
$245,432,884 be used to set rates in this docket.25

        Entergy pointed to an additional $533,002 of purchased-power capacity expenses that
were properly included in Entergy’s rate-filing package, but not provided for in the proposal for
decision.26 The Commission finds that an additional $533,002 ($6,132 for test-year expenses for
Southwest Power Pool fees, $654,082 for Toledo Bend hydro fixed-charges, and -$127,212 for
an Entergy intra-system billing adjustment that were all recorded in FERC account 555) of
purchased-power capacity costs were incurred during the test-year and should be added to the
purchased-power capacity costs in Entergy’s revenue requirement. The Commission modifies
findings of fact 72 and 86 to reflect the inclusion of the additional $533,002 of test-year
purchased-power capacity costs, increasing the total amount to $245,965,886.


                                F. Labor Costs – Incentive Compensation
        The ALJs found that $6,196,037, representing Entergy’s financially-based incentives paid
in the test-year, should be removed from Entergy’s O&M expenses.27 The ALJs agreed with
Commission Staff and Cities that an additional reduction should be made to account for the
FICA taxes that Entergy would have paid for those costs,28 but did not include this reduction in a
finding of fact.


        23
             PFD at 108-09.
        24
             Id. at 109.
        25
             Id.
        26
             Entergy’s Exceptions to the Proposal for Decision at 51.
        27
             PFD at 175.
        28
             Id. at 175-76.
PUC Docket No. 39896                               Order on Rehearing                        Page 8 of 44
SOAH Docket No. XXX-XX-XXXX


        The Commission agrees with the ALJs, but modifies finding of fact 133 to specifically
include the decision that an additional reduction should be made to account for the FICA taxes
Entergy would have paid on the disallowed financially-based incentive compensation. The
Commission notes that this reduction for FICA taxes is reflected in the schedules attached to this
Order.29


                                         G. Affiliate Transactions
        OPUC argued that Entergy’s sales and marketing expenses exclusively benefit the larger
commercial and industrial customers, but the majority of the sales, marketing, and customer
service expenses are allocated to the operating companies based on customer counts. Therefore,
the majority of these expenses are allocated to residential and small business customers. OPUC
argued that it is inappropriate for residential and small business customers to pay for these
expenses.30 The ALJs did not adopt OPUC’s position on this issue.

        The Commission agrees with OPUC and reverses the proposal for decision regarding
allocation of Entergy’s sales and marketing expense and finds that $2.086 million of sales and
marketing expense should be reallocated using direct assignment.                 The Commission has
previously expressed its preference for direct assignment of affiliate expenses.31                  The
Commission finds that the following amounts should be allocated based on a total-number-of-
customers basis: (1) $46,490 for Project E10PCR56224 – Sales and Marketing – EGSI Texas;
(2) $17,013 for Project F3PCD10049 – Regulated Retail Systems O&M; and (3) $30,167 for
Project F3PPMMALI2 – Middle Market Mkt. Development. The remainder, $1,992,475, should
be assigned to (1) General Service, (2) Large General Service and (3) Large Industrial Power
Service.32 The reallocation has the effect of increasing the revenue requirement allocated to the
large business class customers and reduces the revenue requirement for small business and
residential customers. New finding of fact 164A is added to reflect the proper allocation of these
affiliate transactions.


        29
             See Commission Number Run-Memorandum at 3 (Aug. 28, 2012).
        30
             Direct Testimony of Carol Szerszen, OPUC Ex. 1 at 44-45.
        31
          Application of Central Power and Light Company for Authority to Change Rates, Docket No. 14965,
Second Order on Rehearing at 87, COL 29 (Oct. 16, 1997).
        32
             Direct Testimony of Carol Szerszen, OPUC Ex. 1 at Schedule CAS-7.
PUC Docket No. 39896                                 Order on Rehearing                         Page 9 of 44
SOAH Docket No. XXX-XX-XXXX


                                            H. Fuel Reconciliation
       Entergy proposed to allocate costs for the fuel reconciliation to customers using a line-
loss study performed in 1997. Entergy conducted a line-loss study for the year ending December
31, 2010, which falls in the middle of the two year fuel reconciliation period—July 2009 through
June 2011—and therefore reflects the actual line losses experienced by the customer classes
during the reconciliation period. Cities argued that the allocation of fuel costs incurred over the
reconciliation period should reflect the current line-loss study performed by Entergy for this case
and recommended approval on a going-forward basis.                        Fuel factors under P.U.C. SUBST.
R. 25.237(a)(3) are temporary rates subject to revision in a reconciliation proceeding described
in P.U.C. SUBST. R. 25.236.              P.U.C. SUBST. R. 25.236(d)(2) defines the scope of a fuel
reconciliation proceeding to include any issue related to the reasonableness of a utility’s fuel
expenses and whether the utility has over- or under-recovered its reasonable fuel expenses.33
Cities calculated a $3,981,271 reduction to the Texas retail fuel expenses incurred over the
reconciliation period using the current line-losses.                   The ALJs rejected Cities’ proposed
adjustment finding that the P.U.C. SUBST. R. 25.237(c)(2)(B) requires the use of Commission-
approved line losses that were in effect at the time fuel costs were billed to customers in a fuel
reconciliation.34

       The Commission agrees with Cities and reverses the proposal for decision regarding
which line-loss factors should be used in Entergy’s fuel reconciliation. Entergy used the 2010
study line-loss calculations to calculate the demand- and energy-related allocations in its cost of
service analysis supporting its requested base rates. These same currently available line-loss
factors should have been utilized in Entergy’s fuel reconciliation. The Commission finds that
Entergy’s 2010 line-loss factors should be used to calculate Entergy’s fuel reconciliation
over-recovery. As a result, Entergy’s fuel reconciliation over-recovery should be reduced by
$3,981,271. Finding of fact 246A and conclusions of law 19A and 19B are added to reflect the
Commission’s finding that the 2010 line-loss factors be used to reconcile Entergy’s fuel costs.




       33
            Cities’ Exceptions to the Proposal for Decision at 20-21 (July 23, 2012).
       34
            PFD at 327-328.
PUC Docket No. 39896                              Order on Rehearing                  Page 10 of 44
SOAH Docket No. XXX-XX-XXXX


                                      I. MISO Transition Expenses
       During the Commission’s consideration of the proposal for decision, the parties that
contested the amount of Entergy’s MISO transition expenses and how the transition expenses
should be accounted for reached announced on the record that they had reached an agreement on
these issues.35 Those parties agreed that the MISO transition expenses would not be deferred and
that Entergy’s base rates should include $1.6 million for MISO transition expense.36          The
Commission adopts the agreement of the parties and accordingly modifies finding of fact 251
and deletes finding of fact 252.


                             J. Purchased-Power Capacity Cost Baseline
       The Commission modified the amount of purchased-power capacity expense in the
test-year to be $245,965,886 (see section E above). Finding of fact 255 is modified to reflect the
change to the proper test-year purchased-power capacity expense.


                                              K. Other Issues
       New findings of fact 17A, 17B, 17C, 17D, and 17 E are added to reflect procedural
aspects of the case after issuance of the proposal for decision.

       In addition, to reflect corrections recommended by the ALJs, findings of fact 116, 123,
192, 194, and 202 are modified; and new finding of fact 182A is added.


The Commission adopts the following findings of fact and conclusions of law:


                                           II. Findings of Fact

Procedural History
1.     Entergy Texas, Inc. (ETI or the company) is an investor-owned electric utility with a
       retail service area located in southeastern Texas.




       35
            Open Meeting Tr. at 138 (Aug. 17, 2012).
       36
            Id.
PUC Docket No. 39896                         Order on Rehearing                           Page 11 of 44
SOAH Docket No. XXX-XX-XXXX


2.     ETI serves retail and wholesale electric customers in Texas. As of June 30, 2011, ETI
       served approximately 412,000 Texas retail customers. The Federal Energy Regulatory
       Commission (FERC) regulates ETI’s wholesale electric operations.

3.     On November 28, 2011, ETI filed an application requesting approval of: (1) a proposed
       increase in annual base rate revenues of approximately $111.8 million over adjusted test-
       year revenues; (2) a set of proposed tariff schedules presented in the Electric Utility Rate
       Filing Package for Generating Utilities (RFP) accompanying ETI’s application and
       including new riders for recovery of costs related to purchased-power capacity and
       renewable energy credit requirements; (3) a request for final reconciliation of ETI’s fuel
       and purchased-power costs for the reconciliation period from July 1, 2009 to
       June 30, 2011; and (4) certain waivers to the instructions in RFP Schedule V
       accompanying ETI’s application.

4.     The 12-month test-year employed in ETI’s filing ended on June 30, 2011 (test-year).

5.     ETI provided notice by publication for four consecutive weeks before the effective date
       of the proposed rate change in newspapers having general circulation in each county of
       ETI’s Texas service territory. ETI also mailed notice of its proposed rate change to all of
       its customers. Additionally, ETI timely served notice of its statement of intent to change
       rates on all municipalities retaining original jurisdiction over its rates and services.

6.     The following parties were granted intervenor status in this docket: Office of Public
       Utility Counsel; the cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe,
       Dayton, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge
       North, Orange, Pine Forest, Rose City, Pinehurst, Port Arthur, Port Neches, Shenandoah,
       Silsbee, Sour Lake, Splendora, Vidor, and West Orange (Cities), the Kroger Co.
       (Kroger); State Agencies; Texas Industrial Energy Consumers; East Texas Electric
       Cooperative, Inc.; the United States Department of Energy (DOE); and Wal-Mart Stores
       Texas, LLC, and Sam’s East, Inc. (Wal-Mart). The Staff (Staff) of the Public Utility
       Commission of Texas (Commission or PUC) was also a participant in this docket.

7.     On November 29, 2011, the Commission referred this case to the State Office of
       Administrative Hearings (SOAH).
PUC Docket No. 39896                       Order on Rehearing                          Page 12 of 44
SOAH Docket No. XXX-XX-XXXX


8.     On December 7, 2011, the Commission issued its order requesting briefing on threshold
       legal/policy issues.

9.     On December 19, 2011, the Commission issued its Preliminary Order, identifying 31
       issues to be addressed in this proceeding.

10.    On December 20, 2011, the Administrative Law Judges (ALJs) issued SOAH Order
       No. 2, which approved an agreement among the parties to establish a June 30, 2012
       effective date for the company’s new rates resulting from this case pursuant to certain
       agreed language and consolidate Application of Entergy Texas, Inc. for Authority to Defer
       Expenses Related to its Proposed Transition to Membership in the Midwest Independent
       System Operator, Docket No. 39741 (pending) into this proceeding. Although it did not
       agree, Staff did not oppose the consolidation.

11.    On January 13, 2012, the ALJs issued SOAH Order No. 4 granting the motions for
       admission pro hac vice filed by Kurt J. Boehm and Jody M. Kyler to appear and
       participate as counsel for Kroger and the motion for admission pro hac vice filed by Rick
       D. Chamberlain to appear and participate as counsel for Wal-Mart.

12.    On January 19, 2012, the Commission issued a supplemental preliminary order
       identifying two additional issues to be addressed in this case and concluding that the
       company’s proposed purchased-power capacity rider should not be addressed in this case
       and that such costs should be recovered through base rates.

13.    ETI timely filed with the Commission petitions for review of the rate ordinances of the
       municipalities exercising original jurisdiction within its service territory.     All such
       appeals were consolidated for determination in this proceeding.

14.    On April 4, 2012, the ALJs issued SOAH Order No. 13 severing rate case expense issues
       into Application of Entergy Texas, Inc. for Rate Case Expenses Severed from PUC
       Docket No. 39896, Docket No. 40295 (pending).

15.    On April 13, 2012, ETI adjusted its request for a proposed increase in annual base rate
       revenues to approximately $104.8 million over adjusted test-year revenues.

16.    The hearing on the merits commenced on April 24 and concluded on May 4, 2012.
PUC Docket No. 39896                          Order on Rehearing                     Page 13 of 44
SOAH Docket No. XXX-XX-XXXX


17.    Initial post-hearing briefs were filed on May 18 and reply briefs were filed on May 30,
       2012.

17A.   On August 7, 2012, the SOAH ALJs filed a letter with the Commission recommending
       changes to the PFD.

17B    At the July 27, 2012 open meeting, ETI agreed to extend time to August 31, 2012 to
       provide the Commission sufficient time to consider the issues in this proceeding.

17C.   The Commission considered the proposal for decision at the August 17, 2012 and August
       30, 2012 open meetings.

17D.   At the August 30, 2012 open meeting, ETI agreed to extend time to September 14, 2012
       to provide the Commission sufficient time to consider the issues in this proceeding.

17E.   At the August 17, 2012 open meeting, parties announced on the record a settlement of the
       amount of costs for the transition to MISO.

Rate Base
18.    Capital additions that were closed to ETI’s plant-in-service between July 1, 2009 and
       June 30, 2011, are used and useful in providing service to the public and were prudently
       incurred.

19.    ETI’s proposed Hurricane Rita regulatory asset was an issue resolved by the black-box
       settlement in Application of Entergy Texas, Inc. for Authority to Change Rates and
       Reconcile Fuel Costs, Docket No. 37744 (Dec. 13, 2010).

20.    Accrual of carrying charges on the Hurricane Rita regulatory asset should have ceased
       when Docket No. 37744 concluded because the asset would have then begun earning a
       rate of return as part of rate base.

21.    The appropriate calculation of the Hurricane Rita regulatory asset should begin with the
       amount claimed by ETI in Docket No. 37744, less amortization accruals to the end of the
       test-year in the present case, and less the amount of additional insurance proceeds
       received by ETI after the conclusion of Docket No. 37744.

22.    A Test-Year-end balance of $15,175,563 for the Hurricane Rita regulatory asset should
       remain in rate base, applying a five-year amortization rate beginning August 15, 2010.
PUC Docket No. 39896                        Order on Rehearing                         Page 14 of 44
SOAH Docket No. XXX-XX-XXXX


23.    The Hurricane Rita regulatory asset should not be moved to the storm damage insurance
       reserve.

24.    The company requested in rate base its prepaid pension assets balance of $55,973,545,
       which represents the accumulated difference between the Statement of Financial
       Accounting Standards (SFAS) No. 87 calculated pension costs each year and the actual
       contributions made by the company to the pension fund.

25.    The prepaid pension assets balance includes $25,311,236 capitalized to construction work
       in progress (CWIP).

26.    It is not necessary to the financial integrity of ETI to include CWIP in rate base, and there
       was insufficient evidence showing that major projects under construction were efficiently
       and prudently managed.

27.    The portion of the prepaid pension assets balance that is capitalized to CWIP should not
       be included in ETI’s rate base.

28.    The remainder of the prepaid pension assets balance should be included in ETI’s rate
       base.

28A.   When items are excluded from rate base, the related ADFIT should also be excluded.
       The amount of ADFIT associated with the $25 million capitalized to CWIP and excluded
       from rate base is $8,858,933.      The adjusted ADFIT for the prepaid pension asset
       remaining in Entergy’s rate base should be reduced by $8,858,933.

29.    ETI should be permitted to accrue an allowance for funds used during construction on the
       portion of ETI’s Prepaid Pension Assets Balance capitalized to CWIP.

30.    The Financial Accounting Standard Board (FASB) Financial Interpretation No. 48
       (FIN 48), “Accounting for Uncertainty in Income Taxes,” requires ETI to identify each of
       its uncertain tax positions by evaluating the tax position on its technical merits to
       determine whether the position, and the corresponding deduction, is more-likely-than-not
       to be sustained by the Internal Revenue Service (IRS) if audited.

31.    FIN 48 requires ETI to remove the amount of its uncertain tax positions from its
       Accumulated Deferred Federal Income Tax (ADFIT) balance for financial reporting
PUC Docket No. 39896                         Order on Rehearing                        Page 15 of 44
SOAH Docket No. XXX-XX-XXXX


       purposes and record it as a potential liability with interest to better reflect the company’s
       financial condition.

32.    At test-year-end, ETI had $5,916,461 in FIN 48 liabilities, meaning ETI has, thus far,
       avoided paying to the IRS $5,916,461 in tax dollars (the FIN 48 liability) in reliance upon
       tax positions that the company believes will not prevail in the event the positions are
       challenged, via an audit, by the IRS.

33.    ETI has deposited $1,294,683 with the IRS in connection with the FIN 48 liability.

34.    The IRS may never audit ETI as to its uncertain tax positions creating the FIN 48
       liability.

35.    Even if ETI is audited, ETI might prevail on its uncertain tax positions.

36.    ETI may never have to pay the IRS the FIN 48 liability.

37.    Other than the amount of its deposit with the IRS, ETI has current use of the FIN 48
       liability funds.

38.    Until actually paid to the IRS, the FIN 48 liability represents cost-free capital and should
       be deducted from rate base.

39.    The amount of $4,621,778 (representing ETI’s full FIN 48 liability of $5,916,461 less the
       $1,294,683 cash deposit ETI has made with the IRS for the FIN 48 liability) should be
       added to ETI’s ADFIT and thus be used to reduce ETI’s rate base.

40.    ETI’s application and proposed tariffs do not include a request for a tracking mechanism
       or rider to collect a return on the FIN 48 liability.

40A.   It is appropriate for ETI to create a deferred-tax-account tracker in the form of a rider to
       recover on a prospective basis an after–tax return of 8.27% on the amounts paid to the
       IRS that result from an unfavorable FIN 48 audit. The rider will track unfavorable FIN
       48 rulings and the return will be applied prospectively to FIN 48 amounts disallowed by
       an IRS audit after such amounts are actually paid to the federal government. If ETI
       prevails in an appeal of a FIN 48 decision, then any amounts collected under the rider
       related to that decision should be credited back to ratepayers.
PUC Docket No. 39896                      Order on Rehearing                         Page 16 of 44
SOAH Docket No. XXX-XX-XXXX


41.    Deleted.

42.    Investor-owned electric utilities may include a reasonable allowance for cash working
       capital in rate base as determined by a lead-lag study conducted in accordance with the
       Commission’s rules.

43.    Cash working capital represents the amount of working capital, not specifically addressed
       in other rate base items, that is necessary to fund the gap between the time expenditures
       are made and the time corresponding revenues are received.

44.    The lead-lag study conducted by ETI considered the actual operations of ETI, adjusted
       for known and measurable changes, and is consistent with P.U.C. SUBST.
       R. 25.231(c)(2)(B)(iii).

45.    It is reasonable to establish ETI’s cash working capital requirement based on ETI’s lead-
       lag study as updated in Jay Joyce’s rebuttal testimony and on the cost of service approved
       for ETI in this case.

46.    As a result of the black-box settlements in Application of Entergy Gulf States, Inc. for
       Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800 (Nov. 7,
       2008) and Docket No. 37744, the Commission did not approve ETI’s storm damage
       expenses since 1996 and its storm damage reserve balance.

47.    ETI established a prima facie case concerning the prudence of its storm damage expenses
       incurred since 1996.

48.    Adjustments to the storm damage reserve balance proposed by intervenors should be
       denied.

49.    The Hurricane Rita regulatory asset should not be moved to the storm damage insurance
       reserve.

50.    ETI’s appropriate Test-Year-end storm reserve balance was negative $59,799,744.

51.    The amount of $9,846,037, representing the value of the average coal inventory
       maintained at ETI’s coal-burning facilities, is reasonable, necessary, and should be
       included in rate base.
PUC Docket No. 39896                        Order on Rehearing                         Page 17 of 44
SOAH Docket No. XXX-XX-XXXX


52.    The Spindletop gas storage facility (Spindletop facility) is used and useful in providing
       reliable and flexible natural gas supplies to ETI’s Sabine Station and Lewis Creek
       generating plants.

53.    The Spindletop facility is critical to the economic, reliable operation of the Sabine Station
       and Lewis Creek generating plants due to their geographic location in the far western
       region of the Entergy system.

54.    It is reasonable and appropriate to include ETI’s share of the costs to operate the
       Spindletop facility in rate base.

55.    Staff recommended updating ETI’s balance amounts for short-term assets to the 13-
       month period ending December 2011, which was the most recent information available.
       Staff’s proposed adjustments should be incorporated into the calculation of ETI’s rate
       base.

56.    The following short-term asset amounts should be included in rate base: prepayments at
       $8,134,351; materials and supplies at $29,285,421; and fuel inventory at $52,693,485.

57.    The amount of $1,127,778, representing costs incurred by ETI when it acquired the
       Spindletop facility, represent actual costs incurred to process and close the acquisition,
       not mere mark-up costs.

58.    ETI’s $1,127,778 in capitalized acquisition costs should be included in rate base because
       ETI incurred these costs in conjunction with the purchase of a viable asset that benefits
       its retail customers.

59.    In its application, ETI capitalized into plant in service accounts some of the incentive
       payments ETI made to its employees. ETI seeks to include those amounts in rate base.

60.    A portion of those capitalized incentive accounts represent payments made by ETI for
       incentive compensation tied to financial goals.

61.    The portion of ETI’s incentive payments that are capitalized and that are financially-
       based should be excluded from ETI’s rate base because the benefits of such payments
       inure most immediately and predominantly to ETI’s shareholders, rather than its electric
PUC Docket No. 39896                         Order on Rehearing                      Page 18 of 44
SOAH Docket No. XXX-XX-XXXX


       customers.     ETI’s capitalized incentive compensation that is financially based is
       $335,752.96 and should be removed for rate base.

62.    The test-year for ETI’s prior ratemaking proceeding ended on June 30, 2009, and the
       reasonableness of ETI’s capital costs (including capitalized incentive compensation) for
       that prior period was dealt with by the Commission in that proceeding and is not at issue
       in this proceeding.

63.    In this proceeding, ETI’s capitalized incentive compensation that is financially-based
       should be excluded from rate base, but only for incentive costs that ETI capitalized
       during the period from July 1, 2009 (the end of the prior test-year) through June 30, 2010
       (the commencement of the current test-year).

Rate of Return and Cost of Capital
64.    A return on common equity (ROE) of 9.80 percent will allow ETI a reasonable
       opportunity to earn a reasonable return on its invested capital.

65.    The results of the discounted cash flow model and risk premium approach support a ROE
       of 9.80 percent.

65A.   It is not appropriate to add 15 points to the ROE due to unsettled economic conditions
       facing utilities.

66.    A 9.80 percent ROE is consistent with ETI’s business and regulatory risk.

67.    ETI’s proposed 6.74 percent embedded cost of debt is reasonable.

68.    The appropriate capital structure for ETI is 50.08 percent long-term debt and
       49.92 percent common equity.

69.    A capital structure composed of 50.08 percent debt and 49.92 percent equity is
       reasonable in light of ETI’s business and regulatory risks.

70.    A capital structure composed of 50.08 percent debt and 49.92 percent equity will help
       ETI attract capital from investors.
PUC Docket No. 39896                         Order on Rehearing                        Page 19 of 44
SOAH Docket No. XXX-XX-XXXX


71.    ETI’s overall rate of return should be set as follows:

                                 CAPITAL                                    WEIGHTED AVG
      COMPONENT                  STRUCTURE           COST OF CAPITAL        COST OF CAPITAL
      LONG-TERM DEBT             50.08%              6.74%                  3.38%
      COMMON EQUITY              49.92%              9.80%                  4.89%
          TOTAL                  100.00%                                    8.27%

Operating Expenses
72.    ETI’s test-year purchased capacity expenses were $245,965,886.

73.    ETI requested an upward adjustment of $30,809,355 as a post-test-year adjustment to its
       purchased capacity costs. This request was based on ETI’s projections of its purchased
       capacity expenses during a period beginning June 1, 2012 and ending May 31, 2013 (the
       rate-year).

74.    ETI’s purchased capacity expense projections were based on estimates of rate-year
       expenses for: (a) reserve equalization payments under Schedule MSS-1; (b) payments
       under third-party capacity contracts; and (c) payments under affiliate contracts.

75.    ETI’s projection of its rate-year reserve equalization payments under Schedule MSS-1 is
       based on numerous assumptions, including load growths for ETI and its affiliates, future
       capacity contracts for ETI and its affiliates, and future values of the generation assets of
       ETI and its affiliates.

76.    There is substantial uncertainty with regard to ETI’s projection of its rate-year reserve
       equalization payments under Schedule MSS-1.

77.    ETI’s projection of its rate-year third-party capacity contract payments includes
       numerous assumptions, one of which is that every single third-party supplier will perform
       at the maximum level under the contract, even though that assumption is inconsistent
       with ETI’s historical experience.

78.    There is substantial uncertainty with regard to ETI’s projection of its rate-year third-party
       capacity-contract payments.

79.    ETI’s estimates of its rate-year purchases under affiliate contracts are based on a
       mathematical formula set out in Schedule MSS-4.
PUC Docket No. 39896                        Order on Rehearing                       Page 20 of 44
SOAH Docket No. XXX-XX-XXXX


80.    The MSS-4 formula for rate-year affiliate capacity payments reflects that these payments
       will be based on ratios and costs that cannot be determined until the month that the
       payments are to be made.

81.    Over $11 million of ETI’s affiliate transactions were based on a 2013 contract (the EAI
       WBL Contract) that was not signed until April 11, 2012.

82.    There is uncertainty about whether the EAI WBL Contract will ever go into effect.

83.    ETI projects purchasing over 300 megawatts (MW) more in purchased capacity in the
       rate-year than it purchased in the test-year.

84.    ETI experienced substantial load growth in the two years before the test-year, and it
       continues to project similar load growth in the future.

85.    ETI did not meet its burden of proof to demonstrate that a known and measurable
       adjustment of $30,809,355 should be made to its test-year purchased capacity expenses.

86.    ETI’s purchased capacity expense in this case should be based on the test-year level of
       $245,965,886.

87.    ETI incurred $1,753,797 of transmission equalization expense during the test-year.

88.    ETI proposed an upward adjustment of $8,942,785 for its transmission equalization
       expense. This request was based on ETI’s projections of its transmission equalization
       expenses during the rate-year.

89.    The transmission equalization expense that ETI will pay in the rate-year will depend on
       future costs and loads for each of the Entergy operating companies.

90.    ETI’s projection of its rate-year transmission equalization expenses is uncertain and
       speculative because it depends on a number of variables, including future transmission
       investments, deferred taxes, depreciation reserves, costs of capital, tax rates, operating
       expenses, and loads of each of the Entergy operating companies.

91.    ETI seeks increased transmission equalization expenses for transmission projects that are
       not currently used and useful in providing electric service.          ETI’s post-test-year
       adjustment is based on the assumption that certain planned transmission projects will go
PUC Docket No. 39896                          Order on Rehearing                        Page 21 of 44
SOAH Docket No. XXX-XX-XXXX


       into service after the test-year.      At the close of the hearing, none of the planned
       transmission projects had been fully completed and some were still in the planning phase.

92.    It is not reasonable for ETI to charge its retail ratepayers for transmission equalization
       expenses related to projects that are not yet in-service.

93.    ETI’s request for a post-test-year adjustment of $8,942,785 for rate-year transmission
       equalization expenses should be denied because those expenses are not known and
       measurable. ETI’s post-test-year adjustment does not with reasonable certainty reflect
       what ETI’s transmission equalization expense will be when rates are in effect.

94.    ETI’s transmission equalization expense in this case should be based on the test-year
       level of $1,753,797.

95.    P.U.C. SUBST. R. 25.231(c)(2)(ii) states that the reserve for depreciation is the
       accumulation of recognized allocations of original cost, representing the recovery of
       initial investment over the estimated useful life of the asset.

96.    Except in the case of the amortization of the general plant deficiency, the use of the
       remaining life depreciation method to recover differences between theoretical and actual
       depreciation reserves is the most appropriate method and should be continued.

97.    It is reasonable for ETI to calculate depreciation reserve allocations on a straight-line
       basis over the remaining, expected useful life of the item or facility.

98.    Except as described below, the service lives and net salvage rates proposed by the
       company are reasonable, and these service lives and net salvage rates should be used in
       calculating depreciation rates for the company’s production, transmission, distribution,
       and general plant assets.

99.    A 60-year life for Sabine Units 4 and 5 is reasonable for purposes of establishing
       production plant depreciation rates.

100.   The retirement (actuarial) rate method, rather than the interim retirement method, should
       be used in the development of production plant depreciation rates.

101.   Production plant net salvage is reasonably based on the negative five percent net salvage
       in existing rates.
PUC Docket No. 39896                      Order on Rehearing                        Page 22 of 44
SOAH Docket No. XXX-XX-XXXX


102.   The net salvage rate of negative 10 percent for ETI’s transmission structures and
       improvements (FERC Account 352) is the most reasonable of those proposed and should
       be adopted.

103.   The net salvage rate of negative 20 percent for ETI’s transmission station equipment
       (FERC Account 353) is the most reasonable of those proposed and should be adopted.

104.   The net salvage rate of negative five percent for ETI’s transmission towers and fixtures
       (FERC Account 354) is the most reasonable of those proposed and should be adopted.

105.   The net salvage rate of negative 30 percent for ETI’s transmission poles and fixtures
       (FERC Account 355) is the most reasonable of those proposed and should be adopted.

106.   The net salvage rate of negative 30 percent for ETI’s transmission overhead conductors
       and devices (FERC Account 356) is the most reasonable of those proposed and should be
       adopted.

107.   A service life of 65 years and a dispersion curve of R3 for ETI’s distribution structures
       and improvements (FERC Account 361) are the most reasonable of those proposed and
       should be approved.

108.   A service life of 40 years and a dispersion curve of R1 for ETI’s distribution poles,
       towers, and fixtures (FERC Account 364) are the most reasonable of those proposed and
       should be approved.

109.   A service life of 39 years and a dispersion curve of R0.5 for ETI’s distribution overhead
       conductors and devices (FERC Account 365) are the most reasonable of those proposed
       and should be approved.

110.   A service life of 35 years and a dispersion curve of R1.5 for ETI’s distribution
       underground conductors and devices (FERC Account 367) are the most reasonable of
       those proposed and should be approved.

111.   A service life of 33 years and a dispersion curve of L0.5 for ETI’s distribution line
       transformers (FERC Account 368) are the most reasonable of those proposed and should
       be approved.
PUC Docket No. 39896                       Order on Rehearing                       Page 23 of 44
SOAH Docket No. XXX-XX-XXXX


112.   A service life of 26 years and a dispersion curve of L4 for ETI’s distribution overhead
       service (FERC Account 369.1) are the most reasonable of those proposed and should be
       approved.

113.   The net salvage rate of negative five percent for ETI’s distribution structures and
       improvements (FERC Account 361) is the most reasonable of those proposed and should
       be adopted.

114.   The net salvage rate of negative 10 percent for ETI’s distribution station equipment
       (FERC Account 362) is the most reasonable of those proposed and should be adopted.

115.   The net salvage rate of negative seven percent for ETI’s distribution overhead conductors
       and devices (FERC Account 365) is the most reasonable of those proposed and should be
       adopted.

116.   The net salvage rate of positive five percent for ETI’s distribution line transformers
       (FERC Account 368) is the most reasonable of those proposed and should be adopted.

117.   The net salvage rate of negative 10 percent for ETI’s distribution overhead services
       (FERC Account 369.1) is the most reasonable of those proposed and should be adopted.

118.   The net salvage rate of negative 10 percent for ETI’s distribution underground services
       (FERC Account 369.2) is the most reasonable of those proposed and should be adopted.

119.   A service life of 45 years and a dispersion curve of R2 for ETI’s general structures and
       improvements (FERC Account 390) are the most reasonable of those proposed and
       should be approved.

120.   The net salvage rate of negative 10 percent for ETI’s general structures and
       improvements (FERC Account 390) is the most reasonable of those proposed and should
       be adopted.

121.   It is reasonable to convert the $21.3 million deficit that has developed over time in the
       reserve for general plant accounts to General Plant Amortization.

122.   A ten-year amortization of the deficit in the reserve for general plant accounts is
       reasonable and should be adopted.
PUC Docket No. 39896                         Order on Rehearing                        Page 24 of 44
SOAH Docket No. XXX-XX-XXXX


123.   FERC pronouncement AR-15 requires amortization over the same life as recommended
       based on standard life analysis. A standard life analysis determined that a five-year life
       was appropriate for general plant computer equipment (FERC Account 391.2).
       Therefore, a five year amortization for this account is reasonable and should be adopted.

124.   ETI proposed adjustments to its test-year payroll costs to reflect: (a) changes to employee
       headcount levels at ETI and Entergy Services, Inc. (ESI); and (b) approved wage
       increases set to go into effect after the end of the test-year.

125.   The proposed payroll adjustments are reasonable but should be updated to reflect the
       most recent available information on headcount levels as proposed by Commission Staff.
       In addition to adjusting payroll expense levels, the more recent headcount numbers
       should be used to adjust the level of payroll tax expense, benefits expense, and savings
       plan expense.

126.   Staff has appropriately updated headcount levels to the most recent available data but
       errors made by Staff should be corrected. The corrections related to: (a) a double
       counting of three ETI and one ESI employee; (b) inadvertent use of the ETI benefits cost
       percentage in the calculation of ESI benefits costs; (c) an inappropriate reduction of
       savings plan costs when such costs were already included in the benefits percentage
       adjustments; and (d) corrections for full-time equivalents calculations.        Staff’s ETI
       headcount adjustment (AG-7) overstated operation and maintenance (O&M) payroll
       reduction by $224,217, and ESI headcount adjustment (AG-7) understated O&M payroll
       increase by $37,531.

127.   ETI included $14,187,744 for incentive compensation expenses in its cost of service.

128.   The compensation packages that ETI offers its employees include a base payroll amount,
       annual incentive programs, and long-term incentive programs. The majority of the
       compensation is for operational measures, but some is for financial measures.

129.   Incentive compensation that is based on financial measures is of more immediate and
       predominant benefit to shareholders, whereas incentive compensation based on
       operational measures is of more immediate and predominant benefit to ratepayers.
PUC Docket No. 39896                          Order on Rehearing                     Page 25 of 44
SOAH Docket No. XXX-XX-XXXX


130.   Incentives to achieve operational measures are necessary and reasonable to provide utility
       services but those to achieve financial measures are not.

131.   The $5,376,975 that was paid for long term incentive programs was tied to financial
       measures and, therefore, should not be included in ETI’s cost of service.

132.   Of the amounts that were paid pursuant to the Executive Annual Incentive Plan, $819,062
       was tied to financial measures and, therefore, should be disallowed.

133.   In total, the amount of incentive compensation that should be disallowed is $6,196,037
       because it was related to financial measures that are not reasonable and necessary for the
       provision of electric service. An additional reduction should be made to account for the
       FICA taxes ETI would have paid on the disallowed financially based incentive
       compensation.

134.   The amount of incentive compensation that should be included in the cost of service is
       $7,991,707.

135.   To attract and retain highly qualified employees, the Entergy companies provide a total
       package of compensation and benefits that is equivalent in scope and cost with what other
       comparable companies within the utility business and other industries provide for their
       employees.

136.   When using a benchmark analysis to compare companies’ levels of compensation, it is
       reasonable to view the market level of compensation as a range rather than a precise,
       single point.

137.   ETI’s base pay levels are at market.

138.   ETI’s benefits plan levels are within a reasonable range of market levels.

139.   ETI’s level of compensation and benefits expense is reasonable and necessary.

140.   ETI provides non-qualified supplemental executive retirement plans for highly
       compensated individuals such as key managerial employees and executives that, because
       of limitations imposed under the Internal Revenue Code, would otherwise not receive
       retirement benefits on their annual compensation over $245,000 per year.
PUC Docket No. 39896                        Order on Rehearing                         Page 26 of 44
SOAH Docket No. XXX-XX-XXXX


141.   ETI’s non-qualified supplemental executive retirement plans are discretionary costs
       designed to attract, retain, and reward highly compensated employees whose interests are
       more closely aligned with those of the shareholders than the customers.

142.   ETI’s non-qualified executive retirement benefits in the amount of $2,114,931 are not
       reasonable or necessary to provide utility service to the public, not in the public interest,
       and should not be included in ETI’s cost of service.

143.   For the employee market in which ETI operates, most peer companies offer moving
       assistance. Such assistance is expected by employees, and ETI would be placed at a
       competitive disadvantage if it did not offer relocation expenses.

144.   ETI’s relocation expenses were reasonable and necessary.

145.   The company’s requested operating expenses should be reduced by $40,620 to reflect the
       removal of certain executive prerequisites proposed by Staff.

146.   Staff properly adjusted the company’s requested interest expense of $68,985 by removing
       $25,938 from FERC account 431 (using the interest rate of 0.12 percent for calendar year
       2012), leaving a recommended interest expense of $43,047.

147.   During the test-year, ETI’s property tax expense equaled $23,708,829.

148.   ETI requested an upward pro forma adjustment of $2,592,420, to account for the property
       tax expenses ETI estimates it will pay in the rate-year.

149.   ETI’s requested pro forma adjustment is not reasonable because it is based, in part, upon
       the prediction that ETI’s property tax rate will be increased in 2012, a change that is
       speculative is not known and measurable.

150.   Staff’s recommendation to increase ETI’s test-year property tax expenses by $1,214,688
       is based on the historical effective tax rate applied to the known test-year-end plant in
       service value, consistent with Commission precedent, and based upon known and
       measurable changes.

151.   ETI’s test-year property tax burden should be adjusted upward by $1,222,106 for a total
       expense of $24,921,022.
PUC Docket No. 39896                       Order on Rehearing                         Page 27 of 44
SOAH Docket No. XXX-XX-XXXX


152.   Staff recommended reducing ETI’s advertising, dues, and contributions expenses by
       $12,800. The recommendation, which no party contested, should be adopted.

153.   The final cost of service should reflect changes to cost of service that affect other
       components of the revenue requirement such as the calculation of the Texas state gross
       receipts tax, the local gross receipts tax, the PUC Assessment Tax and the Uncollectible
       Expenses.

154.   The company’s requested Federal income tax expense is reasonable and necessary.

155.   ETI’s request for $2,019,000 to be included in its cost of service to account for the
       company’s annual decommissioning expenses associated with River Bend is not
       reasonable because it is not based upon “the most current information reasonably
       available regarding the cost of decommissioning” as required by P.U.C. SUBST.
       R. 25.231(b)(1)(F)(i).

156.   Based on the most current information reasonably available, the appropriate level of
       decommissioning costs to be included in ETI’s cost of service is $1,126,000.

157.   ETI’s appropriate total annual self-insurance storm damage reserve expense is
       $8,270,000, comprised of an annual accrual of $4,400,000 to provide for average annual
       expected storm losses, plus an annual accrual of $3,870,000 for 20 years to restore the
       reserve from its current deficit.

158.   ETI’s appropriate target self-insurance storm damage reserve is $17,595,000.

159.   ETI should continue recording its annual storm damage reserve accrual until modified by
       a Commission order.

160.   The operating costs of the Spindletop facility are reasonable and necessary.

161.   The operating costs of the Spindletop facility paid to PB Energy Storage Services are
       eligible fuel expenses.

Affiliate Transactions
162.   ETI affiliates charged ETI $78,998,777 for services during the test-year. The majority of
       these O&M expenses—$69,098,041—were charged to ETI by ESI.                 The remaining
       affiliate services were charged (or credited) to ETI by: Entergy Gulf States Louisiana,
PUC Docket No. 39896                         Order on Rehearing                        Page 28 of 44
SOAH Docket No. XXX-XX-XXXX


       L.L.C.; Entergy Arkansas, Inc.; Entergy Louisiana, LLC; Entergy Mississippi, Inc.;
       Entergy Operations, Inc.; and non-regulated affiliates.

163.   ESI follows a number of processes to ensure that affiliate charges are reasonable and
       necessary and that ETI and its affiliates are charged the same rate for similar services.
       These processes include: (a) the use of service agreements to define the level of service
       required and the cost of those services; (b) direct billing of affiliate expenses where
       possible; (c) reasonable allocation methodologies for costs that cannot be directly billed;
       (d) budgeting processes and controls to provide budgeted costs that are reasonable and
       necessary to ensure appropriate levels of service to its customers; and (e) oversight
       controls by ETI’s Affiliate Accounting and Allocations Department.

164.   Affiliates charged expenses to ETI through 1292 project codes during the test-year.

164A. The $2,086,145 in affiliate transactions related to sales and marketing expenses should be
       reallocated using direct assignment. The following amounts should be allocated to all
       retail classes in proportion to number of customers:                (1) $46,490 for Project
       E10PCR56224 – Sales and Marketing – EGSI Texas; (2) $17,013 for Project
       F3PCD10049 – Regulated Retail Systems O&M; and (3) $30,167 for Project
       F3PPMMALI2 – Middle Market Mkt. Development. The remainder, $1,992,475, should
       be assigned to (1) General Service, (2) Large General Service and (3) Large Industrial
       Power Service.

165.   ETI agreed to remove the following affiliate transactions from its application:
       (1) Project F3PPCASHCT (Contractual Alternative/Cashpo) in the amount of $2,553;
       (2) Project F3PCSPETEI (Entergy-Tulane Energy Institute) in the amount of $14,288;
       and (3) Project F5PPKATRPT (Storm Cost Processing & Review) in the amount of $929.

166.   The $356,151 (which figure includes the $112,531 agreed to by ETI) of costs associated
       with Projects F5PCZUBENQ (Non-Qualified Post Retirement) and F5PPZNQBDU (Non
       Qual Pension/Benf Dom Utl) are costs that are not reasonable and necessary for the
       provision of electric utility service and are not in the public interest.

167.   The $10,279 of costs associated with Project F3PPFXERSP (Evaluated Receipts
       Settlement) are not normally-recurring costs and should not be recoverable.
PUC Docket No. 39896                        Order on Rehearing                         Page 29 of 44
SOAH Docket No. XXX-XX-XXXX


168.   The $19,714 of costs associated with Project F3PPEASTIN (Willard Eastin et al) are
       related to ESI’s operations, it is more immediately related to Entergy Louisiana, Inc. and
       Entergy New Orleans, Inc. As such, they are not recoverable from Texas ratepayers.

169.   The $171,032 of costs associated with Project F3PPE9981S (Integrated Energy
       Management for ESI) are research and development costs related to energy efficiency
       programs. As such, they should be recovered through the energy efficiency cost recovery
       factor rather than base rates.

170.   Except as noted in the above findings of fact Nos. 162-169, all remaining affiliate
       transactions were reasonable and necessary, were allowable, were charged to ETI at a
       price no higher than was charged by the supplying affiliate to other affiliates, and the rate
       charged is a reasonable approximation of the cost of providing service.

Jurisdictional Cost Allocation
171.   ETI has one full or partial requirements wholesale customer – East Texas Electric
       Cooperative, Inc.

172.   ETI proposes that 150 MW be set as the wholesale load for developing retail rates in this
       docket. Using 150 MW to set the wholesale load is reasonable. The 150 MW used to set
       the wholesale load results in a retail production demand allocation factor of
       95.3838 percent.

173.   The 12 Coincident Peak (12 CP) allocation method is consistent with the approach used
       by the FERC to allocate between jurisdictions.

174.   Using 12CP methodology to allocate production costs between the wholesale and retail
       jurisdictions is the best method to reflect cost responsibility and is appropriate based on
       ETI’s reliance on capacity purchases.

Class Cost Allocation and Rate Design
175.   There is no express statutory authorization for ETI’s proposed Renewable Energy Credits
       rider (REC rider).

176.   REC rider constitutes improper piecemeal ratemaking and should be rejected.
PUC Docket No. 39896                            Order on Rehearing                   Page 30 of 44
SOAH Docket No. XXX-XX-XXXX


177.   ETI’s test-year expense for renewable energy credits, $623,303, is reasonable and
       necessary and should be included in base rates.

178.   Municipal Franchise Fees (MFF) is a rental expense paid by utilities for the right to use
       public rights-of-way to locate its facilities within municipal limits.

179.   ETI is an integrated utility system. ETI’s facilities located within municipal limits
       benefit all customers, whether the customers are located inside or outside of the
       municipal limits.

180.   Because all customers benefit from ETI’s rental of municipal right-of-way, municipal
       franchise fees should be charged to all customers in ETI’s service area, regardless of
       geographic location.

181.   It is reasonable and consistent with the Public Utility Regulatory Act (PURA)
       § 33.008(b) that MFF be allocated to each customer class on the basis of in-city kilowatt
       hour (kWh) sales, without an adjustment for the MFF rate in the municipality in which a
       given kWh sale occurred.

182.   The same reasons for allocating and collecting MFF as set out in Finding of Fact
       Nos. 178-181 also apply to the allocation and collection of Miscellaneous Gross Receipts
       Taxes. The company’s proposed allocation of these costs to all retail customer classes
       based on customer class revenues relative to total revenues is appropriate.

182A. ETI’s proposed gross plant-based allocator is an appropriate method for allocating the
       Texas franchise tax.

183.   The Average and Excess (A&E) 4CP method for allocating capacity-related production
       costs, including reserve equalization payments, to the retail classes is a standard
       methodology and the most reasonable methodology.

184.   The A&E 4CP method for allocating transmission costs to the retail classes is standard
       and the most reasonable methodology.

185.   ETI appropriately followed the rate class revenue requirements from its cost of service
       study to allocate costs among customer classes. ETI’s revenue allocation properly sets
       rates at each class’s cost of service.
PUC Docket No. 39896                         Order on Rehearing                        Page 31 of 44
SOAH Docket No. XXX-XX-XXXX


186.   It is reasonable for ETI to eliminate the service condition for Rate Groups A and C in
       Schedule SHL [Street and Highway Lighting Service] that charges a $50 fee for any
       replacement of a functioning light with a lower-wattage bulb.

187.   It is appropriate to require ETI to prepare and file, as part of its next base rate case, a
       study regarding the feasibility of instituting LED-based rates and, if the study shows that
       such rates are feasible, ETI should file proposals for LED-based lighting and traffic
       signal rates in its next rate case.

188.   An agreement was reached by the parties and approved by the Commission in Docket
       No. 37744 that directed ETI to exclude, in its next rate case, the life-of-contract demand
       ratchet for existing customers in the Large Industrial Power Service (LIPS), Large
       Industrial Power Service-Time of Day, General Service, General Service-Time of Day,
       Large General Service, and Large General Service-Time of Day rate schedules.

189.   ETI’s proposed tariffs in this case did not remove the life-of-contract demand ratchet
       from these rate schedules consistent with the parties’ agreement in Docket No. 37744.

190.   A perpetual billing obligation based on a life-of-contract demand ratchet, as ETI
       proposed, is not reasonable.

191.   ETI’s proposed LIPS and LIPS Time of Day tariffs should be modified to reflect the
       agreement that was adopted by the Commission as just and reasonable in Docket
       No. 37744. Accordingly, these tariffs should be modified as set out in Findings of Fact
       No. 192-194.

192.   ETI’s Schedule LIPS and LIPS Time of Day § VI should be changed to read:
                       DETERMINATION OF BILLING LOAD

                       The kW of Billing Load will be the greatest of the following:

                       (A) The Customer’s maximum measured 30-minute
                       demand during any 30-minute interval of the current billing
                       month, subject to §§ III, IV and V above; or

                       (B) 75% of Contract Power as defined in § VII; or

                       (C) 2,500 kW.
PUC Docket No. 39896                        Order on Rehearing                         Page 32 of 44
SOAH Docket No. XXX-XX-XXXX


193.   ETI’s Schedule LIPS and LIPS Time of Day § VII should be changed to read:
                       DETERMINATION OF CONTRACT POWER

                       Unless Company gives customer written notice to the contrary,
                       Contract Power will be defined as below:

                       Contract Power - the highest load established under § VI(A) above
                       during the 12 months ending with the current month. For the
                       initial 12 months of Customer’s service under the currently
                       effective contract, the Contract Power shall be the kW specified in
                       the currently effective contract unless exceeded in any month
                       during the initial 12-month period.

194.   The Large General Service, Large General Service-Time of Day, General Service, and
       General Service-Time of Day schedules should be similarly revised to eliminate ETI’s
       life-of-contract demand ratchet.

195.   In its proposed rate design for the LIPS class, the company took a conservative approach
       and increased the current rates by an equal percentage. This minimized customer bill
       impacts while maintaining cost causation principles on a rate class basis.

196.   It is a reasonable move towards cost of service to add a customer charge of $630 to the
       LIPS rate schedule with subsequent increases to be considered in subsequent base rate
       cases.

197.   It is a reasonable move towards cost of service to slightly decrease the LIPS energy
       charges   and    increase   the    demand   charges   as   proposed    by    Staff   witness
       William B. Abbott.

198.   DOE proposed a new Schedule LIPS rider—Schedule “Schedulable Intermittent
       Pumping Service” (SIPS) for load schedulable at least four weeks in advance, that occurs
       in the off-season (October through May), that can be cancelled at any time, and for load
       not lasting more than 80 hours in a year. For customers whose loads match these SIPS
       characteristics (for example, DOE’s Strategic Petroleum Reserve), the 12-month demand
       ratchet provision of Schedule LIPS does not apply to demands set under the provisions of
       the SIPS rider. The monthly demand set under the SIPS provisions would be applicable
       for billing purposes only in the month in which it occurred. In short, if a customer set a
PUC Docket No. 39896                       Order on Rehearing                        Page 33 of 44
SOAH Docket No. XXX-XX-XXXX


       12-month ratchet demand in that month, it would be forgiven and not applicable in the
       succeeding 12 months.

199.   DOE’s proposed Schedule SIPS is not restricted solely to the DOE and should be
       adopted. It more closely addresses specific customer characteristics and provides for
       cost-based rates, as does another ETI rider applicable to Pipeline Pumping Service.

200.   Standby Maintenance Service (SMS) is available to customers who have their own
       generation equipment and who contract for this service from ETI.

201.   P.U.C. SUBST. R. 25.242(k)(1) provides that rates for sales of standby and maintenance
       power to qualifying facilities should recognize system wide costing principles and should
       not be discriminatory.

202.   It is reasonable to move Schedule SMS toward cost of service by: (a) adding a customer
       charge equivalent to that of the LIPS rate schedule only for SMS customers not
       purchasing supplementary power under another applicable rate; and (b) revising the tariff
       as follows:
                                       Distribution        Transmission
                        Charge
                                    (less than 69KV)    (69KV and greater)
                      Billing Load Charge ($/kW):
                      Standby            $2.46                  $0.79
                      Maintenance        $2.27                  $0.60
                      Non-Fuel Energy Charge (¢/kWh)
                      On-Peak          4.245¢                   4.074¢
                      Off-Peak         0.575¢                   0.552¢


203.   ETI’s Additional Facilities Charge rider (Schedule AFC) prescribes the monthly rental
       charge paid by a customer when ETI installs facilities for that customer that would not
       normally be supplied, such as line extensions, transformers, or dual feeds.

204.   ETI existing Schedule AFC provides two pricing options. Option A is a monthly charge.
       Option B, which applies when a customer elects to amortize the directly-assigned
       facilities over a shorter term ranging from one to ten years, has a variable monthly
       charge.   There is also a term charge that applies after the facility has been fully
       depreciated.
PUC Docket No. 39896                        Order on Rehearing                          Page 34 of 44
SOAH Docket No. XXX-XX-XXXX


205.   It is reasonable and cost-based to reduce the Schedule AFC Option A rate to 1.11 percent
       per month of the installed cost of all facilities included in the agreement for additional
       facilities.

206.   It is reasonable and cost-based to reduce the Schedule AFC Option B monthly rate and
       the Post Term Recovery Charge as follows:

       Selected Recovery Term Recovery Term Charge            Post Recovery Term Charge
                      1                     9.52%                        0.28%
                      2                     5.14%                        0.28%
                      3                     3.68%                        0.28%
                      4                     2.95%                        0.28%
                      5                     2.52%                        0.28%
                      6                     2.23%                        0.28%
                      7                     2.03%                        0.28%
                      8                     1.88%                        0.28%
                      9                     1.76%                        0.28%
                     10                     1.67%                        0.28%


207.   The revisions in the above findings of fact to Schedule AFC rates reasonably reflect the
       costs of running, operating, and maintaining the directly-assigned facilities.

208.   It is reasonable to modify the Large General Service rate schedule by increasing the
       demand charge from $8.56 to $11.43; decreasing the energy charge from $.00854 to
       $.00458; and reducing the customer charge to $260.00.

209.   Staff’s proposed change to the General Service (GS) rate schedule to gradually move GS
       customers towards their cost of service by recommending a decrease in the customer
       charge from the current rate of $41.09 to $39.91, and a decrease in the energy charges is
       reasonable and should be adopted.

210.   ETI’s Residential Service (RS) rate schedule is composed of two elements: a customer
       charge and a consumption-based energy charge. In the months November through April
       (winter), the rates are structured as a declining block, in which the price of each unit is
       reduced after a defined level of usage. ETI’s proposed increase in the RS customer
       charge to $6 per month is reasonable and should be adopted. For the RS summer rate and
PUC Docket No. 39896                           Order on Rehearing                    Page 35 of 44
SOAH Docket No. XXX-XX-XXXX


       the first winter block rate, the 6.296¢ per kWh energy charge resulting from the increased
       revenue requirement for residential customers is reasonable and should be adopted.

211.   ETI’s Schedule RS declining block rate structure is contrary to energy-efficiency efforts
       and the Legislature’s goal of reducing both energy demand and energy consumption in
       Texas, as stated in PURA § 39.905.

212.   Schedule RS winter block rates should be modified consistent with the goal set out in
       PURA § 39.905, with the initial phase-in of a 20 percent reduction in the block
       differential proposed by ETI and subsequent reductions should be reviewed for
       consideration at the occurrence of each rate case filing.

213.   Other elements of Schedule RS are just and reasonable.

Fuel Reconciliation
214.   ETI incurred $616,248,686 in natural-gas expenses during the reconciliation period,
       which is from July 2009 through June 2011.

215.   ETI purchased natural gas in the monthly and daily markets and pursuant to a long-term
       contract with Enbridge Inc. pipeline. ETI also transported gas on its own account and
       negotiated operational balancing agreements with various pipeline companies.

216.   ETI employed a diversified portfolio of gas supply and transportation agreements to meet
       its natural-gas requirements, and ETI prudently managed its gas-supply contracts.

217.   ETI’s natural gas expenses were reasonable and necessary expenses incurred to provide
       reliable electric service to retail customers.

218.   ETI incurred $90,821,317 in coal expenses during the reconciliation period.

219.   ETI prudently managed its coal and coal-related contracts during the reconciliation
       period.

220.   ETI monitored and audited coal invoices from Louisiana Generating, LLC for coal
       burned at the Big Cajun II, Unit 3 facility.

221.   ETI’s coal expenses were reasonable and necessary expenses incurred to provide reliable
       electric service to retail customers.
PUC Docket No. 39896                        Order on Rehearing                       Page 36 of 44
SOAH Docket No. XXX-XX-XXXX


222.   ETI incurred $990,041,434 in purchased-energy expenses during the reconciliation
       period.

223.   The Entergy System’s planning and procurement processes for purchased-power
       produced a reasonable mix of purchased resources at a reasonable price.

224.   During the reconciliation period, ETI took advantage of opportunities in the fuel and
       purchased-power markets to reduce costs and to mitigate against price volatility.

225.   ETI’s purchased-energy expenses were reasonable and necessary expenses incurred to
       provide reliable electric service to retail customers.

226.   ETI provided sufficient contemporaneous documentation to support the reasonableness of
       its purchased-power planning and procurement processes and its actual power purchases
       during the reconciliation period.

227.   The Entergy system sold power off system when the revenues were expected to be more
       than the incremental cost of supplying generation for the sale, subject to maintaining
       adequate reserves.

228.   The System Agreement is the tariff approved by the FERC that provides the basis for the
       operation and planning of the Entergy system, including the six operating companies.
       The System Agreement governs the wholesale-power transactions among the operating
       companies by providing for joint operation and establishing the bases for equalization
       among the operating companies, including the costs associated with the construction,
       ownership, and operation of the Entergy system facilities.

229.   Under the terms of the Entergy System Agreement, ETI was allocated its share of
       revenues and expenses from off-system sales.

230.   During the reconciliation period, ETI recorded off-system sales revenue in the amount of
       $376,671,969 in FERC Account 447 and credited 100 percent of off-system sales
       revenues and margins from off-system sales to eligible fuel expenses.

231.   ETI properly recorded revenues from off-system sales and credited those revenues to
       eligible fuel costs.
PUC Docket No. 39896                        Order on Rehearing                         Page 37 of 44
SOAH Docket No. XXX-XX-XXXX


232.   The Entergy system consists of six operating companies, including ETI, which are
       planned and operated as a single, integrated electric system under the terms of the System
       Agreement.

233.   Service schedule MSS-1 of the System Agreement determines how the capability and
       ownership costs of reserves for the Entergy system are equalized among the operating
       companies.    These inter-system “reserve equalization” payments are the result of a
       formula rate related to the Entergy system’s reserve capability that is applied on a
       monthly basis.

234.   Reserve capability under service schedule MSS-1 is capability in excess of the Entergy
       system’s actual or planned load built or acquired to ensure the reliable, efficient operation
       of the electric system.

235.   By approving service schedule MSS-1, the FERC has approved the method by which the
       operating companies share the cost of maintaining sufficient reserves to provide
       reliability for the Entergy system as a whole.

236.   Service schedule MSS-3 of the System Agreement determines the pricing and exchange
       of energy among the operating companies. By approving service schedule MSS-3, the
       FERC has approved the method by which the operating companies are reimbursed for
       energy sold to the exchange energy pool and how that energy is purchased.

237.   Service schedule MSS-4 of the System Agreement sets forth the method for determining
       the payment for unit power purchases between operating companies. By approving
       service schedule MSS-4, the FERC has approved the methodology for pricing
       inter-operating company unit power purchases.

238.   The Entergy system is planned using multi-year, annual, seasonal, monthly, and next-day
       horizons. Once the planning process has identified the most economical resources that
       can be used to reliably meet the aggregate Entergy system demand, the next step is to
       procure the fuel necessary to operate the generating units as planned and acquire
       wholesale power from the market.
PUC Docket No. 39896                          Order on Rehearing                      Page 38 of 44
SOAH Docket No. XXX-XX-XXXX


239.   Once resources are procured to meet forecasted load, the Entergy system is operated
       during the current day using all the resources available to meet the total Entergy system
       demand.

240.   After current-day operation, the System Agreement prescribes an accounting protocol to
       bill the costs of operating the system to the individual operating companies.          This
       protocol is implemented via the intra-system bill to each operating company on a
       monthly basis.

241.   ETI purchased power from affiliated operating companies per the terms of service
       schedule MSS-3 of the System Agreement. The payments made under Schedule MSS-3
       to affiliated operating companies are reasonable and necessary, and the FERC has
       approved the pricing formula and the obligation to purchase the energy. ETI pays the
       same price per megawatt hour for energy under service schedule MSS-3 as does any
       other operating company purchasing energy under service schedule MSS-3 during the
       same hour.

242.   The Spindletop facility is used primarily to ensure gas-supply reliability and guard
       against gas-supply curtailments that can occur as a result of extreme weather or other
       unusual events.

243.   The Spindletop facility provides a secondary benefit of flexibility in gas supply. ETI can
       back down gas-fired generation to take advantage of more economical wholesale power,
       or use gas from storage to supplement gas-fired generation when load increases during
       the day and thereby avoid more expensive intra-day gas purchases.

244.   ETI’s customers received benefits from the Spindletop facility during the reconciliation
       period through reliable gas supplies and ETI’s monthly and daily storage activity.

245.   ETI prudently managed the Spindletop facility to provide reliability and flexibility of gas
       supply for the benefit of customers.

246.   ETI proposed new loss factors, based on a December 2010 line-loss study, to be applied
       for the purpose of allocating its costs to its wholesale customers and retail customer
       classes.
PUC Docket No. 39896                            Order on Rehearing                     Page 39 of 44
SOAH Docket No. XXX-XX-XXXX


246A. ETI’s 2010 line-loss factors should be used to reconcile ETI’s fuel costs. Therefore,
       ETI’s fuel reconciliation over-recovery should be reduced by $3,981,271.

247.   ETI’s proposed loss factors are reasonable and shall be implemented on a prospective
       basis as a result of this final order.

248.   ETI seeks a special-circumstances exception to recover $99,715 resulting from the
       FERC’s reallocation of rough production equalization costs in FERC Order No. 720-A,
       and to treat such costs as eligible fuel expense.

249.   Special circumstances exist and it is appropriate for ETI to recover the rough production
       cost equalization costs reallocated to ETI as a result of the FERC’s decision in Order
       No. 720-A.

Other Issues
250.   A deferred accounting of ETI’s Midwest Independent Transmission System Operator
       (MISO) transition expenses is not necessary to carry out any requirement of PURA.

251.   ETI should include $1.6 million in base rates for MISO transition expense.

252.   Deleted.

253.   Transmission Cost Recovery Factor baseline values should be set during the compliance
       phase of this docket, after the Commission makes final rulings on the various contested
       issues that may affect this calculation.

254.   Distribution Cost Recovery Factor baseline values should be set during the compliance
       phase of this docket, after the Commission makes final rulings on the various contested
       issues that may affect this calculation.

255.   The appropriate amount for ETI’s purchased-power capacity expense to be included in
       base rates is $245,965,886.

256.    The amount of ETI’s purchased-power capacity expense includes third-party contracts,
       legacy affiliate contracts, other affiliate contracts, and reserve equalization. Whether the
       amounts for all contracts should be included in the baseline for a purchased-capacity rider
       that may be approved in Project No. 39246 is an issue that should be decided in that
       project.
PUC Docket No. 39896                        Order on Rehearing                         Page 40 of 44
SOAH Docket No. XXX-XX-XXXX


                                   III. Conclusions of Law
1.     ETI is a “public utility” as that term is defined in PURA § 11.004(1) and an “electric
       utility” as that term is defined in PURA § 31.002(6).

2.     The Commission exercises regulatory authority over ETI and jurisdiction over the subject
       matter of this application pursuant to PURA §§ 14.001, 32.001, 32.101, 33.002, 33.051,
       36.101–.111, and 36.203.

3.     SOAH has jurisdiction over matters related to the conduct of the hearing and the
       preparation of a proposal for decision in this docket, pursuant to PURA § 14.053 and
       TEX. GOV’T CODE ANN. § 2003.049.

4.     This docket was processed in accordance with the requirements of PURA and the Texas
       Administrative Procedure Act, Tex. Gov’t Code Ann. Chapter 2001.

5.     ETI provided notice of its application in compliance with PURA § 36.103, P.U.C. PROC.
       R. 22.51(a), and P.U.C. SUBST. R. 25.235(b)(1)-(3).

6.     Pursuant to PURA § 33.001, each municipality in ETI’s service area that has not ceded
       jurisdiction to the Commission has jurisdiction over the company’s application, which
       seeks to change rates for distribution services within each municipality.

7.     Pursuant to PURA § 33.051, the Commission has jurisdiction over an appeal from a
       municipality’s rate proceeding.

8.     ETI has the burden of proving that the rate change it is requesting is just and reasonable
       pursuant to PURA § 36.006.

9.     In compliance with PURA § 36.051, ETI’s overall revenues approved in this proceeding
       permit ETI a reasonable opportunity to earn a reasonable return on its invested capital
       used and useful in providing service to the public in excess of its reasonable and
       necessary operating expenses.

10.    Consistent with PURA § 36.053, the rates approved in this proceeding are based on
       original cost, less depreciation, of property used and useful to ETI in providing service.

11.    The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059
       and P.U.C. SUBST. R. 25.231(c)(2)(C)(i).
PUC Docket No. 39896                       Order on Rehearing                        Page 41 of 44
SOAH Docket No. XXX-XX-XXXX


12.    Including the cash working capital approved in this proceeding in ETI’s rate base is
       consistent with P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV), which allows a reasonable
       allowance for cash working capital to be included in rate base.

13.    The ROE and overall rate of return authorized in this proceeding are consistent with the
       requirements of PURA §§ 36.051 and 36.052.

14.    The affiliate expenses approved in this proceeding and included in ETI’s rates meet the
       affiliate payment standards articulated in PURA §§ 36.051, 36.058, and Railroad
       Commission of Texas v. Rio Grande Valley Gas Co., 683 S.W.2d 783 (Tex. App.—
       Austin 1984, no writ).

15.    The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059
       and P.U.C. SUBST. R. 25.231(c)(2)(C)(i).

16.    Pursuant to P.U.C. SUBST. R. 25.231(b)(1)(F), the decommissioning expense approved in
       this case is based on the most current information reasonably available regarding the cost
       of decommissioning, the balance of funds in the decommissioning trust, anticipated
       escalation rates, the anticipated return on the funds in the decommissioning trust, and
       other relevant factors.

17.    ETI has demonstrated that its eligible fuel expenses during the reconciliation period were
       reasonable and necessary expenses incurred to provide reliable electric service to retail
       customers as required by P.U.C. SUBST. R. 25.236(d)(1)(A). ETI has properly accounted
       for the amount of fuel-related revenues collected pursuant to the fuel factor during the
       reconciliation period as required by P.U.C. SUBST. R. 25.236(d)(1)(C).

18.    ETI prudently managed the dispatch, operations, and maintenance of its fossil plants
       during the reconciliation period.

19.    The reconciliation period level operating and maintenance expenses for the Spindletop
       facility are eligible fuel expenses pursuant to P.U.C. SUBST. R. 25.236(a).

19A.   Fuel factors under P.U.C. SUBST. R. 25.237(a)(3) are temporary rates subject to revision
       in a reconciliation proceeding.
PUC Docket No. 39896                        Order on Rehearing                         Page 42 of 44
SOAH Docket No. XXX-XX-XXXX


19B.   P.U.C. SUBST. R. 25.236(d)(2) defines the scope of a fuel reconciliation proceeding to
       include any issue related to the reasonableness of a utility’s fuel expenses and whether
       the utility has over- or under-recovered its reasonable fuel expenses. It is proper to use
       the new line-loss study to calculate Entergy’s fuel reconciliation and over-recovery.

20.    Special circumstances are warranted pursuant to P.U.C. SUBST. R. 25.236(a)(6) to
       recover rough production equalization payments reallocated to ETI by the FERC.

21.    ETI’s rates, as approved in this proceeding, are just and reasonable in accordance with
       PURA § 36.003.


                                 IV. Ordering Paragraphs
       In accordance with these findings of fact and conclusions of law, the Commission issues
the following orders:

1.     The proposal for decision prepared by the SOAH ALJs is adopted to the extent consistent
       with this Order.

2.     ETI’s application is granted to the extent consistent with this Order.

3.     ETI shall file in Tariff Control No. 40742 Compliance Tariff Pursuant to Final Order in
       Docket No. 39896 (Application of Entergy Texas, Inc. for Authority to Change Rates,
       Reconcile Fuel Costs, and Obtain Deferred Accounting Treatment) tariffs consistent with
       this Order within 20 days of the date of this Order. No later than ten days after the date
       of the tariff filings, Staff shall file its comments recommending approval, modification,
       or rejection of the individual sheets of the tariff proposal. Responses to the Staff’s
       recommendation shall be filed no later than 15 days after the filing of the tariff. The
       Commission shall by letter approve, modify, or reject each tariff sheet, effective the date
       of the letter.

4.     The tariff sheets shall be deemed approved and shall become effective on the expiration
       of 20 days from the date of filing, in the absence of written notification of modification or
       rejection by the Commission. If any sheets are modified or rejected, ETI shall file
       proposed revisions of those sheets in accordance with the Commission’s letter within ten
PUC Docket No. 39896                         Order on Rehearing                         Page 43 of 44
SOAH Docket No. XXX-XX-XXXX


       days of the date of that letter, and the review procedure set out above shall apply to the
       revised sheets.

5.     Copies of all tariff-related filings shall be served on all parties of record.

6.     ETI shall prepare and file as part of its next base rate case a study regarding the
       feasibility of instituting LED-based rates and, if the study shows that such rates are
       feasible, ETI should file proposals for LED-based lighting and traffic signal rates in that
       case. If ETI has LED lighting customers taking service, the study shall include detailed
       information regarding differences in the cost of serving LED and non-LED lighting
       customers. ETI shall provide the results of this study to Cities and interested parties as
       soon as practicable, but no later than the filing of its next rate case.

7.     All other motions, requests for entry of specific findings of fact and conclusions of law,
       and any other requests for general or specific relief, if not expressly granted, are denied.
PUC Docket No. 39896                                Order on Rehearing                      Page 44 of 44
SOAH Docket No. XXX-XX-XXXX




          SIGNED AT AUSTIN, TEXAS the ______ day of October 2012.


                                                PUBLIC UTILITY COMMISSION OF TEXAS




                                                ______________________________________________
                                                DONNA L. NELSON, CHAIRMAN




                                                ______________________________________________
                                                ROLANDO PABLOS, COMMISSIONER

        I respectfully dissent regarding the utility- and executive-management-class affiliate
transactions. To be consistent with Commission precedent in Docket No. 14965,37 the indirect
costs of the management of Entergy’s ultimate parent should not be borne by Texas ratepayers.
Therefore, I would disallow the following: $173,867 for Project No. F3PCCPM001 (Corporate
Performance Management); $372,919 for Project No. F3PCC31255 (Operations-Office of the
CEO); and $74,485 for Project No. F3PPCOO001 (Chief Operating Officer). I join the
Commission in all other respects for this Order.



                                                ______________________________________________
                                                KENNETH W. ANDERSON, JR., COMMISSIONER


q:\cadm\orders\final\39000\39896o on reh.docx




          37
          Application of Central Power and Light Company for Authority to Change Rates, Docket No. 14965,
Second Order on Rehearing (Oct. 16, 1997).
        APPENDIX C

District Court's Final Judgment
                                    DC          BK1429S PG132

                                                                          Filed In 'fh o·
                                                                           of Travis ~ •strict Cour:·
                                                                                       ounty, Texas
                                                                        EM OCT 1~          tUlli
                              CAUSE NO. D-l-GN-13-000121                 At         (/ .J.q.   A
                                                                         AmaliaRodriguez-Mendoza, c;;~·


ENTERGY TEXAS, INC.,                        §                   IN THE DISTRICT COURT OF
               Plaintiff                    §
                                            §
v.                                          §                   TRAVIS COUNTY, TEXAS
                                            §
PUBLIC UTILITY COMMISSION,                  §
                Defendant                   §                   353RD JUDICIAL DISTRICT


                        ORDER ON ADMINISTRATIVE APPEAL

       On July 22, 2014, the Court heard Plaintiffs appeal from Defendant's Order in PUC

Docket No. 39896, SOAH Docket No. XXX-XX-XXXX. The administrative record was admitted

into evidence, and the Court heard oral argument. Entergy, the Cities, and OPUC each asserted

points of error challenging the Commission's order. Having considered the pleadings, the

evidence and the arguments of counsel, the Court makes the following rulings:


       l . Entergy's Point of Error No. 1 addressing the use of a current line loss study rather
           that a prior-approved line loss study in allocating line loss costs among classes of
           customers establishes that the Commission erred in applying the current study in
           violation of Commission rules found at 16 TAC §25.236(e)(3) and 16 TAC 25.237(a)
           and (c)(2)(B). Accordingly, the Court FINDS that the PUC's ruling was arbitrary and
           capricious and constitutes an error of law. The Court REVERSES such ruling and
           REMANDS this matter to the Commission for further proceedings consistent with
           this Court's Order.
       2. All other points of error are DENIED, and the Commission' s Order is in all other
           respects AFFIRMED.




                                                                J
               APPENDIX D

Commission's Final Order in Docket No. 37744
                                     PUC DOCKET NO. 37744
                                  SOAH DOCKET NO. XXX-XX-XXXX


 APPLICATION OF ENTERGY TEXAS,                          §       PUBLIC UTILITY COMMISSION
 INC. FOR AUTHORITY TO CHANGE                           §
 RATES AND RECONCILE FUEL                               §                      OF TEXAS
 COSTS                                                  §


                                                  ORDER


        This Order addresses the application of Entergy Texas, Inc. (ETI) for authority to change
rates and reconcile fuel costs. ETI, Commission Staff, the Office of Public Utility Counsel
(OPUC), the Steering Committee of Cities Served by ETI (Cities),1 Texas Industrial Energy
Consumers (TIEC), The Kroger Company (Kroger), and Wal-Mart Stores Texas, LLC and
Sam’s East, Inc. (collectively Wal-Mart), through their duly authorized representatives entered
into and filed a stipulation and settlement agreement that resolves all of the issues in this
proceeding except the issues related to ETI’s proposal for competitive generation service.
Cottonwood Energy, L.P. and the State of Texas agencies and institutions of higher education
(State Agencies) did not join but do not oppose the stipulation.

        The Commission severed the competitive generation service issues into Docket
No. 389512 in Order No. 14.

        The Commission adopts the following findings of fact and conclusions of law:




        1
          Steering Committee of Cities is comprised of the Cities of Anahuac, Beaumont, Bridge City, Cleveland,
Conroe, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest,
Pinehurst, Port Arthur, Port Neches, Rose City, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and West
Orange.
        2
        Application of Entergy Texas, Inc. for Approval of Competitive Generation Service Tariff (Issues Severed
From Docket No. 37744), Docket No. 38951.
PUC Docket No. 37744                          Order                                     Page 2 of 15
SOAH Docket No. XXX-XX-XXXX


                                     I.   Findings of Fact

Procedural History
1.     On December 30, 2009, ETI filed an application requesting approval of (1) base rate
       tariffs and riders designed to collect an overall revenue requirement of $1,758.4 million,
       which includes a total non-fuel retail revenue requirement of $838.3 million (base rate
       revenues of $486 million plus revenue from riders of $352.3 million); (2) a set of
       proposed tariff schedules presented in the Electric Utility Rate Filing Package for
       Generating Utilities (RFP) accompanying ETI’s application; (3) a request for final
       reconciliation of ETI’s fuel and purchased power costs for the reconciliation period from
       April 1, 2007 to June 30, 2009; and (4) certain waivers to the instructions in RFP
       Schedule V accompanying ETI’s application.

2.     The 12-month test year employed in ETI’s filing ended on June 30, 2009.

3.     ETI provided notice by publication for four consecutive weeks before the effective date
       of the proposed rate change in newspapers having general circulation in each county of
       ETI’s Texas service territory. ETI also mailed notice of its proposed rate change to all of
       its customers. Additionally, ETI timely served notice of its statement of intent to change
       rates on all municipalities retaining original jurisdiction over its rates and services. ETI
       also published one-time supplemental notice by publication in newspapers and by bill
       insert.

4.     The following parties were granted intervenor status in this docket: OPUC, Cities,
       Cottonwood, Kroger, State Agencies, TIEC, and Wal-Mart. Commission Staff was also a
       participant in this docket.

5.     On January 4, 2010, the Commission referred this case to the State Office of
       Administrative Hearings (SOAH) for processing.

6.     On February 19, 2010, the ALJs issued Order No. 3, which approved an agreement
       between ETI, Staff, Cities, State Agencies, OPUC, TIEC, Kroger, and Wal-Mart, to
       (1) establish an interim rate increase of $17.5 million annually above ETI’s then-existing
       base rates commencing with service rendered on and after May 1, 2010 subject to
       true-up and refund for service rendered prior to September 13, 2010 to the extent final
PUC Docket No. 37744                              Order                                         Page 3 of 15
SOAH Docket No. XXX-XX-XXXX


        overall rates established by the Commission amounted to less than a $17.5 million rate
        increase; (2) extend the jurisdictional deadline by which the Commission must issue a
        final order on the Company’s rate request from July 5, 2010 to November 1, 2010;
        (3) establish a September 13, 2010 effective date for rates such that, notwithstanding the
        extension of the jurisdictional deadline, the final overall rates established by the
        Commission would relate back to service rendered on and after September 13, 2010;
        (4) require ETI to publish supplemental notice, once in newspapers and by a bill insert,
        setting forth the effect of its proposed rate change in terms of the percentage increase in
        non-fuel revenues; and (5) establish a procedural schedule and discovery deadlines for
        this proceeding. Order No. 3 also granted Mr. Kurt Boehm’s motion for admission
        pro hac vice as counsel for Kroger and ETI’s February 3 and February 11, 2010 petitions
        for review of cities’ ordinances and motions to consolidate with respect to the rate
        decisions adopted by the Cities of Ames, Anderson, Bedias, Bevil Oaks, Bremond,
        Caldwell, Calvert, Chester, China, Colmesneil, Corrigan, Cut and Shoot, Daisetta,
        Dayton, Devers, Franklin, Groveton, Hardin, Hearne, Iola, Kosse, Kountze, Liberty,
        Lumberton, Madisonville, Midway, New Waverly, Normangee, Nome, Patton Village,
        Plum Grove, Riverside, Rose Hill Acres, Somerville, Taylor Landing, Todd Mission,
        Trinity, and Woodville.

7.      On June 14, 2010, the ALJs issued Order No. 6 granting Staff’s June 1, 2010 motion and
        severing rate case expense issues to Docket No. 38346.3 Through Order No. 6, the ALJs
        also granted ETI’s March 12, April 29, and May 17 petitions for review and motions to
        consolidate with respect to the rate decisions adopted by the Cities of Anahuac,
        Beaumont, Bridge City, Cleveland, Conroe, Groves, Houston, Huntsville, Montgomery,
        Navasota, Nederland, Oak Ridge North, Orange, Panorama Village, Pine Forest,
        Pinehurst, Port Arthur, Port Neches, Roman Forest, Rose City, Shenandoah, Shepard,
        Silsbee, Sour Lake, Splendora, Vidor, West Orange, Willis, Woodbranch Village, and
        Woodloch.




        3
         Application of Entergy Texas, Inc. for Rate Case Expenses Severed from PUC Docket No. 37744, Docket
No. 38346.
PUC Docket No. 37744                                     Order                                               Page 4 of 15
SOAH Docket No. XXX-XX-XXXX


8.       The hearing on the merits commenced on July 13, 2010 and was immediately recessed in
         order to facilitate settlement negotiations.                  The hearing was again convened on
         July 15, 2010, at which time the signatories announced their intent to continue settlement
         discussions to resolve all issues related to the Company’s application with the exception
         of those related to ETI’s proposal for competitive generation service (CGS) and
         associated riders.

9.       On August 6, 2010, the signatories submitted the stipulation resolving all outstanding
         issues regarding the Company’s application with the exception of those related to ETI’s
         CGS proposal. Under the stipulation, ETI will be allowed to implement base rate tariffs
         and riders designed to collect an overall revenue requirement of $1,614.9 million,4 which
         includes a total non-fuel retail revenue requirement of $694.9 million (base rate revenues
         of $599 million plus revenue from riders of $95.9 million).                           The signatories also
         submitted, on August 6, 2010, an agreed motion to revise interim rates and to consolidate
         the severed rate-case expense docket. The interim rates requested in the agreed motion
         mirrored the final rates proposed for Commission approval in the stipulation. The agreed
         motion further requested that the ALJs consolidate with the instant proceeding Docket
         No. 38346, related to severed Docket No. 37744 rate case expense issues, and admit the
         parties’ pre-filed exhibits into evidence.

10.      On July 16 and July 20, 2010, the ALJs held the hearing on the merits with respect to
         ETI’s CGS proposal.

11.      On August 9, 2010, the ALJs issued Order No. 12, granting approval of revised interim
         rates for usage on and after August 15, 2010.

12.      On October 5, 2010, the ALJs issued a proposal for decision regarding issues related to
         ETI’s CGS proposal.

13.      On October 5, 2010, the ALJs issued Order No. 13, ordering the consolidation of Docket
         No. 38346, related to severed rate-case expense issues, into the instant proceeding,




         4
           This figure includes fuel at test year prices. If current fuel prices are substituted for test year fuel prices,
the overall revenue requirement figure would be $1,504.0 million.
PUC Docket No. 37744                           Order                                     Page 5 of 15
SOAH Docket No. XXX-XX-XXXX


       admitting evidence, and returning this docket to the Commission consistent with the
       agreed motion filed on August 6, 2010.

14.    The Commission considered this Docket at the November 10, 2010 and
       December 1, 2010 open meetings.

15.    On November 30, 2010 ETI filed an unopposed motion to sever the competitive CGS
       issues from the settled issues in this docket. The Commission granted the motion at the
       December 1, 2010 open meeting and the Commission’s decision was memorialized in
       Order No. 14 issued on December 3, 2010. The CGS issues were severed into Docket
       No. 38951 in Order No. 14.

Description of the stipulation and Settlement Agreement
16.    The signatories to the settlement stipulated that ETI should be allowed to implement an
       initial overall increase in base-rate revenues of $59 million for usage on and after
       August 15, 2010. The signatories further stipulated that they would request approval of
       interim rates by the ALJs presiding or by the Commission, as necessary, to ensure timely
       implementation of this initial rate increase. The signatories further stipulated that ETI
       should be allowed to implement an additional overall increase in base-rate revenues of
       $9 million on an annualized basis effective for bills rendered on and after May 2, 2011,
       the first billing cycle for the revenue month of May.

17.    The signatories agreed that ETI’s authorized return on equity shall be 10.125% and its
       weighted average cost of capital shall be 8.5209%.

18.    The signatories stipulated that the amount of rate increase authorized under finding of
       fact 16 includes rate-case expenses and contemplates their full amortization in 2010, and
       that this amount constitutes the full and final recovery of all rate-case expenses relating to
       Docket No. 37744.

19.    The signatories stipulated to the amount of transmission and distribution invested capital
       by function as of June 30, 2009 as set out in attachment 1 to the stipulation.
PUC Docket No. 37744                           Order                                  Page 6 of 15
SOAH Docket No. XXX-XX-XXXX


20.    The signatories stipulated that the Company’s proposed purchased-power recovery rider
       will not be approved in this docket, and purchased capacity costs will be included in
       base rates.

21.    The signatories stipulated that the Company’s proposed transmission cost recovery factor
       (TCRF) will not be approved in this docket. The signatories stipulated to the baseline
       values as shown in attachment 2 to the stipulation to be used in the Company’s request, if
       any, for a TCRF in a separate proceeding.

22.    The signatories agreed that ETI’s proposed cost-of-service adjustment rider and formula
       rate plan will not be approved in this docket.

23.    The signatories stipulated that the Company’s proposed renewable-energy-credit rider
       will not be approved in this docket, and the Company’s renewable-energy-credit costs
       shall be recovered in base rates. The signatories further stipulated that a transmission
       customer that opts out pursuant to P.U.C. SUBST. R. 25.173(j) shall receive a credit that
       offsets the amount of renewable-energy-credit costs that are recovered in base rates from
       the transmission customer.

24.    The signatories agreed that ETI’s proposed remote-communications-link rider should be
       approved as filed by the Company.

25.    The signatories agreed that ETI’s proposed market-valued-energy-reduction service rider
       will not be approved in this docket.

26.    The signatories reached the following specific agreements regarding rate design as a part
       of the overall resolution of this docket:

       a.     Rate Schedule IS. Rate Schedule IS will be opened to new business. In the
              Company’s next base-rate case, the amount of interruptible credits recoverable
              from Texas retail customers shall be limited to an increase of $1 million more
              than the amount requested in this docket (or a total of $6.8 million); provided,
              however, that in the next rate case, the Company may request an exception to this
              limitation upon a showing that the test-year credit amount in excess of the
              $6.8 million cap is both cost effective and necessary to meet the Company’s
              generation reserve margin requirement. The signatories further agreed that the
PUC Docket No. 37744                          Order                                      Page 7 of 15
SOAH Docket No. XXX-XX-XXXX


              Company will not offer additional interruptible service if the availability of total
              interruptible service supplied by the Company under all interruptible service
              riders exceeds 5% of the projected aggregate Company peak demand unless the
              additional level of interruptible service offered in excess of the 5% cap is both
              cost effective and necessary to meet the Company’s generation reserve margin
              requirement. To the extent that the credit amount or participation level exceeds
              the limitations described in this paragraph and the Company includes test-year
              credits over the $6.8 million credit-amount cap or additional participation in
              excess of the 5% participation-level cap in its next rate case, the Company shall
              have the burden to prove whether those test-year credits or participation levels
              meet the standards established in this paragraph for inclusion in the test year. The
              standards in this paragraph are in addition to any requirements in PURA for
              inclusion of costs in rates. The signatories further agreed to the Schedule IS
              revisions shown on attachment 3 to the stipulation.

       b.     Rate Schedule IHE. The signatories agreed that no change shall be made to rate
              schedule IHE in this docket.

       c.     Lighting Class Rates. The signatories stipulated that the language under the
              paragraph relating to rate group C in rate schedule SHL will be revised to reflect
              that, where the Company agrees to install facilities other than its standard street
              light fixture and lamp as provided under Rate Group A, a lump sum payment will
              be required, based upon the installed cost of all facilities excluding the cost of the
              standard street light fixture and lamp, and the customer will be billed under rate
              group A.

       e.     Electric Extension Policy. The signatories agreed to the line-extension terms and
              conditions as reflected in attachment 4 to the stipulation.

       f.     Life-of-Contract   Demand      Ratchet.      The    signatories   agreed    that   the
              life-of-contract demand ratchet provision in rate schedules Large Industrial Power
              Service, Large Industrial Power Service-Time of Day, General Service, General
              Service-Time of Day, Large General Service, and Large General Service-Time of
PUC Docket No. 37744                              Order                                        Page 8 of 15
SOAH Docket No. XXX-XX-XXXX


                Day shall be excluded from rate schedules in ETI’s next rate case.                    The
                signatories further stipulated that the foregoing rate schedules will be revised so
                that the life-of-contract demand ratchet provision shall not be applicable to new
                customers and shall not exceed the level in effect on August 15, 2010 for existing
                customers.

        g.      Residential Customer Charge.           The signatories agreed that the residential
                customer charge shall be increased to $5.00.

        h.      Non-Sufficient Funds Charge.         The signatories agreed that the non-sufficient
                funds charge shall be increased to $15.00.

27.     The signatories agreed to the class cost allocation set forth in attachment 5 to
        the stipulation.

28.     The signatories stipulated that the appropriate allocation between ETI’s wholesale and
        retail jurisdictions of baseline values and costs to be included in a TCRF is to be
        addressed in the proceeding, if any, in which ETI seeks approval of a TCRF.

29.     The signatories stipulated that no party waives its right to address in any subsequent
        proceeding the appropriate treatment for Texas retail ratemaking purposes of power sales
        between ETI and Entergy Gulf States Louisiana, L.L.C.

30.     The signatories reached the following specific agreements regarding fuel-related issues as
        part of the overall resolution of this docket:

        a.      Agreed Fuel Disallowance. The Company stipulated to a fuel disallowance of
                $3.25 million not associated with any particular issue raised by the signatories.
                The disallowance will be allocated pro rata with interest over each month of the
                reconciliation period and reflected in the refund in Docket No. 38403.5 The
                signatories stipulated that the Company’s fuel costs shall be finally reconciled for
                the reconciliation period of April 1, 2007 through June 30, 2009.

        b.      Rider IPCR. The signatories agreed that ETI’s eligible Rider IPCR costs for the


        5
            Application of Entergy Texas, Inc. to Implement an Interim Fuel Refund, Docket No. 38403, Order
(Sept. 16, 2010).
PUC Docket No. 37744                               Order                                         Page 9 of 15
SOAH Docket No. XXX-XX-XXXX


                period April 1, 2007 through the date the rider terminated shall be finally
                reconciled with a disallowance of $300,000. The signatories further agreed that
                the under-recovered balance of Rider IPCR costs shall be booked as fuel expense
                in the month in which the Commission issues an order adopting the stipulation;
                provided, however, that the under-recovered balance shall be allocated to
                customer classes using A&E4CP.

        c.      Rough Production Cost Equalization (RPCE) Payments. The signatories agreed
                that ETI will credit an additional $18.6 million to Texas fuel-factor customers,
                which the signatories stipulated represents the remaining portion of RPCE
                payments ETI received in 2007 that were at issue in Docket No. 35269.6 The
                RPCE credit shall be allocated to rate classes based on loss-adjusted kilowatt
                hours at plant for calendar year 2006. For customers in the Large Industrial
                Power Service rate class, the credit will be refunded based on the customer’s
                actual kWh usage during the billing months of January 2006 through
                December 2006. Upon issuance of a final order approving the stipulation, the
                RPCEs shall be credited to customers as a separate one-month bill credit in the
                same form as the RPCEA Rider last approved in Docket No. 38098.7 ETI agreed
                that it will terminate all appeals related to Docket No. 35269.

31.     The signatories agreed that ETI will continue its accrual of storm-cost reserves at the
        level of $3.65 million annually and that this amount shall be subsumed in the base-rate
        revenue increase described in finding of fact 16 above.

32.     The signatories agreed that ETI shall maintain River Bend depreciation rates at current
        levels, i.e., based on a 60-year life. River Bend decommissioning costs will be set at
        $2,019,000 annually, which is based upon a labor-factor escalation rate of 1.67%, an
        energy-factor escalation rate of 0.25%, and a waste-burial-factor-escalation rate of




        6
         Compliance Filing of Entergy Texas, Inc. Regarding Jurisdictional Allocation of 2007 System Agreement
Payments, Docket No. 35269, Order (Jan. 7, 2009).
        7
          Application of Entergy Texas, Inc. for Authority to Implement New RPCEA Rate, Docket No. 38098,
Order (July 1, 2010).
PUC Docket No. 37744                          Order                                    Page 10 of 15
SOAH Docket No. XXX-XX-XXXX


       1.71%, resulting in an overall escalation rate of 3.62%, and net investment yields as
       follows:
                       Nuclear-Decommissioning-Trust Projected Returns
                                    Tax-Qualified        Non-Tax-Qualified
                                     Investments             Investment

                    2010                          5.475%                   5.057%
                    2011                          5.837%                   5.236%
                    2012                          6.306%                   5.567%
                    2013                          6.304%                   5.607%
                    2014                          6.481%                   5.896%
                    2015                          6.493%                   5.909%
                    2016                          6.412%                   5.826%
                    2017                          6.412%                   5.830%
                    2018                          6.364%                   5.790%
                    2019                          6.316%                   5.748%
                    2020                          6.268%                   5.712%
                    2021                          6.220%                   5.670%
                    2022                          2.503%                   5.458%
                    2023                          5.817%                   5.055%
                    2024                          5.382%                   4.628%
                    2025                          5.036%                   4.516%
                  2026-2034                       4.920%                   4.409%

33.    The signatories stipulated that the Company’s depreciation rates for non-River Bend
       production plant, transmission, distribution, and general plant will remain at current
       levels and the Company will maintain its accounting records on a prospective basis for
       purposes of depreciation accrual, depreciation reserve, retirements, additions, salvage,
       and cost of removal by FERC account.

Consistency of the Agreement with PURA and the Commission Requirements
34.    Considered in light of (1) the pre-filed testimony by the parties entered into evidence and
       (2) the additional evidence and testimony admitted during the course of the hearing on
       the merits on the Company’s application, the stipulation is the result of compromise from
       each signatory, and these efforts, as well as the overall result of the stipulation viewed in
       light of the record evidence as a whole, support the reasonableness and benefits of the
       terms of the stipulation.
PUC Docket No. 37744                            Order                                     Page 11 of 15
SOAH Docket No. XXX-XX-XXXX


35.    The evidence addressed in finding of fact 34 demonstrates that the rates, terms, and
       conditions resulting from the stipulation are just and reasonable and consistent with the
       public interest.

36.    The total level of the Texas retail revenue requirement contemplated by the stipulation
       will allow ETI the opportunity to earn a reasonable return over and above its reasonable
       and necessary operating expense.

37.    The stipulated revenue requirement is consistent with applicable provisions of PURA
       chapter 36 and the Commission’s rules.

38.    To the extent that affiliate costs are included in the stipulated revenue requirement and
       fuel expense, they are reasonable and necessary for each class of affiliate costs presented
       in ETI’s application.

39.    To the extent that affiliate costs are included in the stipulated revenue requirement and
       fuel expense, the price charged to ETI is not higher than the prices charged by the
       supplying affiliate for the same item or class of items to its other affiliates or divisions, or
       a non-affiliated person within the same market area or having the same market
       conditions.

40.    The retail revenue requirement in the stipulation does not include any expenses
       prohibited from recovery under PURA.

41.    A return on equity of 10.125% and a weighted average cost of capital of 8.5209% for ETI
       should be adopted consistent with the stipulation.

42.    The agreed rate-design provisions and terms and conditions of service included in the
       stipulation are just and reasonable.

43.    The treatment of rate-case expenses described in the stipulation is reasonable.

44.    The Company’s proposed remote-communications-link rider as filed by the Company
       is reasonable.

45.    The depreciation rates agreed to in the stipulation are just and reasonable.
PUC Docket No. 37744                              Order                               Page 12 of 15
SOAH Docket No. XXX-XX-XXXX


46.    The recovery of $2,019,000 annually for decommissioning costs of nuclear production
       assets based on the factors agreed to in the stipulation is reasonable.

47.    A $3.65 million annual storm cost accrual is reasonable.

48.    The class allocation methodologies described in the stipulation are just and reasonable.

49.    The fuel and IPCR-related provisions of the stipulation are reasonable.


                                     II.    Conclusions of Law
1.     ETI is a public utility as that term is defined in PURA § 11.004(1) and an electric utility
       as that term is defined in PURA § 31.002(6).

2.     The Commission exercises regulatory authority over ETI and jurisdiction over the subject
       matter of this application pursuant to PURA §§ 14.001, 32.001, 32.101, 33.002, 33.051,
       36.001–.111, 36.203, 39.452, and 39.455.

3.     SOAH has jurisdiction over matters related to the conduct of the hearing and the
       preparation of a proposal for decision in this docket, pursuant to PURA § 14.053 and
       TEX. GOV’T CODE ANN. § 2003.049.

4.     This docket was processed in accordance with the requirements of PURA, the Texas
       Administrative Procedure Act,8 and Commission rules.

5.     ETI provided notice of its application in compliance with PURA § 36.103, P.U.C. PROC.
       R. 22.51(a), and P.U.C. SUBST. R. 25.235(b)(1)-(3).

6.     This docket contains no remaining contested issues of fact or law.

7.     The stipulation, taken as a whole, is a just and reasonable resolution of all issues it
       addresses; results in just and reasonable rates, terms, and conditions; is supported by a
       preponderance of the credible evidence in the record; is consistent with the relevant
       provisions of PURA; and is consistent with the public interest.

8.     ETI has properly accounted for the amount of fuel and IPCR-related revenues collected
       pursuant to the fuel factor and Rider IPCR.


       8
           TEX. GOV’T CODE ANN. Chapter 2001 (Vernon 2007 and Supp. 2009).
PUC Docket No. 37744                           Order                                  Page 13 of 15
SOAH Docket No. XXX-XX-XXXX


9.     The revenue requirement, cost allocation, revenue distribution, and rate design
       implementing the stipulation result in rates that are just and reasonable, comply with the
       ratemaking provisions in PURA, and are not unreasonably discriminatory, preferential, or
       prejudicial.

10.    Based on the evidence in this docket, the overall total invested capital through the end of
       the test year meets the requirement in PURA § 36.053(a) that electric utility rates be
       based on the original cost, less depreciation, of property used by and useful to the utility
       in providing service.

11.    ETI has met its burden of proof in demonstrating that it is entitled to the level of retail
       base rate and rider revenue set out in the stipulation.

12.    ETI has met its burden of proof in demonstrating that the rates resulting from the
       stipulation are just and reasonable, and consistent with PURA.


                                III.     Ordering Paragraphs
1.     ETI’s application seeking authority to change its rates; reconcile its fuel and purchased
       power costs for the Reconciliation Period from April 1, 2007 to June 30, 2009; and for
       other related relief is approved consistent with the above findings of fact and conclusions
       of law.

2.     Rates, terms, and conditions consistent with the stipulation are approved.

3.     The tariffs and riders consistent with the stipulation are approved for the initial and
       second step rate increases.

4.     ETI’s request for waivers of RFP instructions (RFP Schedule V) is granted.

5.     ETI shall adjust decommissioning expense related to the River Bend Nuclear Generating
       Station consistent with the terms of this Order.

6.     Neither the stipulation and settlement agreement nor this Order constitutes the
       Commission's agreement with, or consent to, the manner in which ETI, or any entity
       affiliated with ETI, has interacted with any decommissioning trust to which ETI or its
       ratepayers have made contributions or provided funds. Furthermore, this Order in no
PUC Docket No. 37744                          Order                                    Page 14 of 15
SOAH Docket No. XXX-XX-XXXX


       way constitutes a waiver or release of any conduct, whether or not such conduct occurred
       before the date of this Order, that may constitute a violation of any provision of state law,
       including, without limitation, the rules and regulations of this Commission relating to
       nuclear decommissioning trust funds; or prevents the Staff of the Commission from
       opening an investigation and taking enforcement action relating to violations of such
       rules and regulations.

7.     Nothing contained in this Order constitutes the consent or approval, explicit or implied,
       of any modification, amendment or clarification of any power purchase agreement
       between ETI and any other Entergy entity relating to the River Bend Station. Without
       limiting the foregoing, nothing contained in this Order shall constitute the consent or
       approval of any modification, amendment, or clarification of any power purchase
       agreement between ETI and any other Entergy entity relating to the River Bend Station,
       which is made to address any concerns raised by the NRC in its Request for Additional
       Information regarding the River Bend Station dated March 11, 2010.

8.     The Rider IPCR costs and eligible fuel costs requested by ETI are, consistent with this
       Order, reconciled through June 30, 2009, and are approved consistent with the
       stipulation.

9.     ETI shall adjust its fuel over/under recovery balance consistent with the findings in this
       Order.

10.    ETI shall file an RPCEA Rider consistent with the above findings of fact and conclusions
       of law to be effective with the first billing cycle of the billing month immediately
       following the effective date of this Order.

11.    Because the final approved rates are equal to or higher than the interim rates adopted in
       Order No. 3, no refund of the interim rates authorized by Order No. 3 is necessary.

12.    The interim rates approved in Order No. 12 are herby approved for the initial step rate
       increase contemplated by the stipulation, and ETI shall implement the second step rates
       for bills rendered on and after May 2, 2011, the first billing cycle for the revenue month
       of May.
PUC Docket No. 37744                                Order                                Page 15 of 15
SOAH Docket No. XXX-XX-XXXX


13.       Within 30 days of the date of this Order, ETI shall file a clean copy of all of the tariffs
          and schedules approved in this docket and a clean copy of the attachments to the
          stipulation.

14.       The entry of this Order consistent with the stipulation does not indicate the Commission’s
          endorsement of any principle or method that may underlie the stipulation. Neither should
          entry of this Order be regarded as a precedent as to the appropriateness of any principle
          or methodology underlying the stipulation.

15.       All other motions, requests for entry of specific findings of fact, conclusions of law, and
          ordering paragraphs, and any other requests for general or specific relief, if not expressly
          granted in this order, are hereby denied.


          SIGNED AT AUSTIN, TEXAS the ______ day of December 2010


                                          PUBLIC UTILITY COMMISSION OF TEXAS




                                          BARRY T. SMITHERMAN, CHAIRMAN




                                          DONNA L. NELSON, COMMISSIONER




                                          KENNETH W. ANDERSON, JR., COMMISSIONER


q:\cadm\orders\final\37000\37744fo.docx
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                                                                 ·PRESENTATION ON BEHALF OF
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·3·                                                             ··ENTERGY
                                                                   ·      TEXAS, INC. (CONTINUED)
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  ·APPLICATION OF ENTERGY· ··)· ·STATE OFFICE OF
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                                                                 ·
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    ·     INC., FOR· · · · ··)
  ·AUTHORITY TO CHANGE RATES )
·5·                                                             ···· ··CHRIS E. BARRILLEAUX
 ··AND
    ·  RECONCILE FUEL COSTS, )                                 ·5·
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  ·AND OBTAIN DEFERRED· · · ·)
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    ·         TREATMENT· · ··) ADMINISTRATIVE HEARINGS          ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·151
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    ·      OF PUBLIC UTILITY COUNSEL (Ferris)· · · · · · ·49    ···· ··MICHAEL P. CONSIDINE
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    ·  UNITED STATES DEPARTMENT OF ENERGY (Porter)· · · ·54    14·
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                                                                   ·        SESSION· · · · · · · · · · · · · · · · · ··365
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    ·       TEXAS, INC.· · · · · · · · · · · · · · · · · ·60   16·
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  ·                                                             ··PRESENTATION
                                                                   ·           ON BEHALF OF
 ···· ··JOSEPH DOMINO                                          17·
                                                                 ·ENTERGY TEXAS, INC. (CONTINUED)· · · · · · · · · · ··366
17·
  · · · · · ·- Direct (Wren)· · · · · · · · · · · · · · ·60    18·
                                                                 · · ··WALTER C. FERGUSON
 ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ··62     ···· · · · ·- Direct (McNally)· · · · · · · · · · · · ·366
18·
  ·
 ··AFTERNOON
    ·         SESSION· · · · · · · · · · · · · · · · · ··103   19·
                                                                 · · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·367
19·
  ·                                                             ···· · · · ·- Redirect (McNally)· · · · · · · · · · · ·369
 ··PRESENTATION
    ·            ON BEHALF OF                                  20·
                                                                 · · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·372
20·
  ·ENTERGY TEXAS, INC. (CONTINUED)                              ···· · · · ·- Further Redirect (McNally)· · · · · · · ·374
 ···                                                           21·
                                                                 ·
21·
  · · ··JOSEPH DOMINO                                           ···· ··DANE A. WATSON
 ···· · · · ·- Cross (Lawton - Continued)· · · · · · · ·103    22·
                                                                 · · · · · ·- Direct (Williams)· · · · · · · · · · · ··376
22·
  · · · · · ·- Cross (VanMiddlesworth)· · · · · · · · ··115     ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·380
 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·131
23·
  · · · · · ·- Redirect (Wren)· · · · · · · · · · · · ··139    23·
                                                                 · · · · · ·- Cross (Lawler)· · · · · · · · · · · · · ·397
 ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·143     ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··403
24·
  · · · · · ·- Recross (VanMiddlesworth)· · · · · · · ··144    24·
                                                                 · · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·410
 ···                                                            ···· · · · ·- Recross (Lawler)· · · · · · · · · · · · ·414
25·
  ·                                                            25·
                                                                 ·


                           KENNEDY REPORTING SERVICE, INC.
                                                 512.474.2233
                                                                                                  Page 51 (Pages 447-450)
                                                                 Page 447                                                                 Page 449

·1·· ·understand your term of human resource costs, to the                  ·1·· · · ·A· ··It's my rebuttal testimony and exhibits.
·2·· ·extent that there were labor dollars applied to a                     ·2·· · · ·Q· ··Okay.··Was your direct testimony, rebuttal
·3·· ·project, and my schedule will often have the impact                   ·3·· ·testimony, and exhibits prepared by you or under your
·4·· ·through the loading of benefits.··And so through that                 ·4·· ·supervision?
·5·· ·mechanism, I see that, but I couldn't tell you that it                ·5·· · · ·A· ··Yes, it was.
·6·· ·had to do with human resource costs in the sense of work              ·6·· · · ·Q· ··Do you have any corrections you need to make to
·7·· ·that I would do or anybody on my staff.                               ·7·· ·your testimony?
·8·· · · ·Q· ··I understand.··But it's in the human resources               ·8·· · · ·A· ··No.
·9·· ·class on your exhibit.                                                ·9·· · · ·Q· ··If I were to ask you the same questions today
10·· · · ·A· ··Ma'am, I understand.                                         10·· ·that were asked in your written testimony, would your
11·· · · ·Q· ··Yes.                                                         11·· ·answers be the same?
12·· · · · · · · · ·MS. KELLEY:··I have no further questions,               12·· · · ·A· ··Yes.
13·· ·and I would offer State Agency Exhibit No. 3.                         13·· · · · · · · · ·MR. OLSON:··All right.··Your Honor, at
14·· · · · · · · · ·JUDGE WALSTON:··Any objection?                          14·· ·this time, we move for the admission of ETI 32 and 59.
15·· · · · · · · · ·MR. BRITT:··Just with the caveat that it's              15·· · · · · · · · ·JUDGE WALSTON:··Okay.··ETI Exhibits 32 and
16·· ·subject to check and verification.                                    16·· ·59 are admitted.
17·· · · · · · · · ·JUDGE WALSTON:··Subject to verification,                17·· · · · · · · · ·(Exhibit ETI Nos. 32 and 59 admitted)
18·· ·State's Exhibit 3 is admitted.                                        18·· · · · · · · · ·MR. OLSON:··All right.··At this time, I
19·· · · · · · · · ·(Exhibit State No. 3 admitted)                          19·· ·offer the witness for cross-examination.
20·· · · · · · · · ·JUDGE WALSTON:··Public Utility Counsel?                 20·· · · · · · · · ·JUDGE WALSTON:··Cities?
21·· · · · · · · · ·MS. FERRIS:··No questions, Your Honor.                  21·· · · · · · · · ·MR. MACK:··No questions.
22·· · · · · · · · ·JUDGE WALSTON:··Okay.··Staff?                           22·· · · · · · · · ·JUDGE WALSTON:··TIEC?
23·· · · · · · · · ·MR. SMYTH:··No questions.                               23·· · · · · · · · ·MS. GRIFFITHS:··Yes, Your Honor.
24·· · · · · · · · ·JUDGE WALSTON:··Redirect?                               24·· ·
25·· · · · · · · · ·MR. BRITT:··No questions, Your Honor.                   25·· ·

                                                                 Page 448                                                                 Page 450

·1··  · · · · · · · ·JUDGE WALSTON:··Okay.··Thank you,                      ·1·· · · · · · · · · · · ·CROSS-EXAMINATION
·2··  ·Mr. Gardner.                                                         ·2·· ·BY MS. GRIFFITHS:
 ·3·· · · · · · · · ·WITNESS GARDNER:··Thank you.                           ·3·· · · ·Q· ··Good afternoon, Mr. McCulla.··You're here today
 ·4·· · · · · · · · ·JUDGE WALSTON:··Will you raise your right              ·4·· ·for your direct and your rebuttal testimony.··Correct?
 ·5·· ·hand?                                                                ·5·· · · ·A· ··That's correct.
 ·6·· · · · · · · · ·(Witness McCulla sworn)                                ·6·· · · ·Q· ··All right.··And what was your title again,
 ·7·· · · · · · · · ·JUDGE WALSTON:··State your full name.                  ·7·· ·Mr. McCulla?
 ·8·· · · · · · · · ·WITNESS McCULLA:··Mark F. McCulla.                     ·8·· · · ·A· ··Vice president of transmission regulatory
 ·9·· · · · · · · · ·JUDGE WALSTON:··Thank you.                             ·9·· ·compliance.
10·· · · · · · · · · · · ·MARK F. McCULLA,                                  10·· · · ·Q· ··Okay.··And as vice president of transmission
11·· ·having been first duly sworn, testified as follows:                   11·· ·and regulatory compliance, you know what MSS-2 means, do
12·· · · · · · · · · · ··DIRECT EXAMINATION                                 12·· ·you not?
13·· ·BY MR. OLSON:                                                         13·· · · ·A· ··Yes.
14·· · · ·Q· ··Mr. McCulla, you just stated your name.··Please              14·· · · ·Q· ··Okay.··What is MSS-2?
15·· ·state your title and position with the Company.                       15·· · · ·A· ··It's schedule that's used for transmission
16·· · · ·A· ··I'm the vice president of transmission                       16·· ·facilities, but certain qualifications are equalized
17·· ·regulatory compliance.                                                17·· ·because they lend themselves to serving the needs of the
18·· · · ·Q· ··Okay.··You have in front of you what has been                18·· ·entire system.
19·· ·marked ETI Exhibit 32.··Do you see that?                              19·· · · ·Q· ··Okay.··So MSS-2 is part of the Entergy system
20·· · · ·A· ··I do.                                                        20·· ·agreement which is a FERC-approved schedule.··Correct?
21·· · · ·Q· ··Can you please identify that exhibit?                        21·· · · ·A· ··That's correct.
22·· · · ·A· ··It's my direct testimony and exhibits.                       22·· · · ·Q· ··All right.··And is it fair to say that what
23·· · · ·Q· ··Okay.··And you also have before you ETI 59.                  23·· ·MSS-2 does is it equalizes the costs of transmission
24·· · · ·A· ··I do.                                                        24·· ·investment across the Entergy system for particular
25·· · · ·Q· ··Can you identify that, please?                               25·· ·transmission projects that I believe are at 230-kV and


                                  KENNEDY REPORTING SERVICE, INC.
                                                             512.474.2233
                                                                                           Page 52 (Pages 451-454)
                                                                Page 451                                                              Page 453

·1·· ·above?··Is that accurate?                                            ·1·· ·don't know if this is the right word or the right way to
·2·· · · ·A· ··230 and above and other qualifications, tie                 ·2·· ·phrase it -- but essentially embodied in this number
·3·· ·lines and other things like that.··But generally 230 and             ·3·· ·that the Company is requesting as an increase in its
·4·· ·above is correct.                                                    ·4·· ·MSS-2 expense.··Is that correct?
·5·· · · ·Q· ··Okay.··And an issue in this case is the amount              ·5·· · · ·A· ··Yes, that's correct.
·6·· ·of MSS-2 expense that the Company is entitled to.··Is                ·6·· · · ·Q· ··All right.··Now, you have some familiarity with
·7·· ·that fair to say?                                                    ·7·· ·the MSS-2 service schedule?
·8·· · · ·A· ··That's one of the issues, yes.                              ·8·· · · ·A· ··Some familiarity.
·9·· · · ·Q· ··All right.··And the Company is requesting, as               ·9·· · · ·Q· ··All right.··Is it accurate that MSS-2 -- that
10·· ·part of its rate request here -- as part of the about                10·· ·there are various inputs to the MSS-2 calculation?··In
11·· ·104 or $10 million -- whatever it is -- rate request --              11·· ·that I mean that there are various inputs to how much
12·· ·approximately $10.6 million in MSS-2 expense.··Correct?              12·· ·each operating company must pay to figure out what their
13·· · · ·A· ··That's correct.                                             13·· ·MSS-2 expense is going to be.
14·· · · ·Q· ··And you offer rebuttal testimony on that issue.             14·· · · ·A· ··I wouldn't say I'm very familiar with the
15·· ·Yes?                                                                 15·· ·calculation that takes place.··I'm familiar with the
16·· · · ·A· ··Yes, I do.                                                  16·· ·assets -- the transmission assets and what -- what I'm
17·· · · ·Q· ··Okay.··So earlier today -- and I'm not sure if              17·· ·familiar with is whether they're determined to be
18·· ·you were here with -- when this testimony was given, but             18·· ·qualified as equalizable or not.··But as far as the
19·· ·Mr. Lawton with the Cities went over the post test year              19·· ·calculation and how it goes into the rates, I'm not as
20·· ·adjustment that the Company did for MSS-2 expense.··Were             20·· ·familiar with that.
21·· ·you here for that?                                                   21·· · · ·Q· ··Okay.··I understand.··And I don't want to test
22·· · · ·A· ··I was not.                                                  22·· ·your knowledge or give you a test on the FERC schedule,
23·· · · ·Q· ··Okay.··I believe what you have in front of                  23·· ·because I counted the pages of the FERC schedule, and
24·· ·you -- it should have been passed out -- is a document               24·· ·it's about a seven-page calculation.
25·· ·that I'm not going to be admitting into the record, but              25·· · · ·A· ··Okay.··Thanks.

                                                                Page 452                                                              Page 454

·1·· ·it is labeled at the bottom WP/PAJ-23.1.                             ·1··  · · ·Q· ··But do you agree that that calculation does
·2·· · · ·A· ··Okay.··I have it in front of me.                            ·2··  ·look at various variables, and one of those variables
·3·· · · ·Q· ··All right.··And that is a workpaper that is a                ·3·· ·will be the -- basically the inter-transmission
·4·· ·backup to Mr. Considine's testimony, because                          ·4·· ·investment on the system?
·5·· ·Mr. Considine also sponsored that post test year                      ·5·· · · ·A· ··Correct.··Yes.
·6·· ·adjustment for MSS-2 expense.                                         ·6·· · · ·Q· ··All right.··And another variable will be the
·7·· · · · · · · · ·If you turn to Page 23.2 at the bottom --               ·7·· ·ownership or operating costs of a particular company.
·8·· ·just flip it over.                                                    ·8·· ·Correct?
·9·· · · ·A· ··Okay.                                                        ·9·· · · ·A· ··The --
10·· · · ·Q· ··All right.··You'll see adjusted total, and                  10·· · · ·Q· ··The ownership or operating costs?
11·· ·under that is approximately $10.7 million.··Correct?                 11·· · · ·A· ··I'm not sure how that goes into it, but --
12·· · · ·A· ··Yes.··Correct.                                              12·· · · ·Q· ··Okay.··Fair enough.··Do you know what the term
13·· · · ·Q· ··Okay.··And that correlates to the amount of                 13·· ·"responsibility ratio" means?
14·· ·MSS-2 expense that the Company is requesting?                        14·· · · ·A· ··I'm not familiar with how it's used.
15·· · · ·A· ··Okay.                                                       15·· · · ·Q· ··Okay.··Do you understand that each particular
16·· · · ·Q· ··Is that accurate?                                           16·· ·operating company makes -- makes or receives MSS-2 --
17·· · · ·A· ··Correct.                                                    17·· · · ·A· ··Okay.
18·· · · ·Q· ··Okay.··And that is not a test year number, but              18·· · · ·Q· ··-- costs based --
19·· ·it is a projected rate year number for MSS-2 expense.                19·· · · ·A· ··Yes.
20·· ·Correct?                                                             20·· · · ·Q· ··-- on its particular responsibility ratio?
21·· · · ·A· ··That's my understanding.··What my rebuttal                  21·· · · ·A· ··Okay.··Yes, I'm familiar with that.
22·· ·testimony was reflecting was the transmission projects               22·· · · ·Q· ··Okay.··So if an operating company has -- I know
23·· ·and their status and expected completion.                            23·· ·it's all relative, but a higher responsibility ratio,
24·· · · ·Q· ··Okay.··But you understand that the projects                 24·· ·its MSS-2 expense may go up depending upon its actual
25·· ·that you discussed in your rebuttal testimony were -- I              25·· ·costs?


                                   KENNEDY REPORTING SERVICE, INC.
                                                              512.474.2233
                                                                                       Page 1 (Pages 1-4)
                                                     Page i                                                      Page iii
  · · · · · · · ··SOAH DOCKET NO. XXX-XX-XXXX
·1·                                                            ·1·
                                                                 · · · · · · · ·TABLE OF CONTENTS (CONTINUED)
 ···                                                           ·2·
                                                                 · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE
  · · · · · · · · · ·PUC DOCKET NO. 39896
·2·
 ···                                                           ·3·
                                                                 ·PRESENTATION ON BEHALF OF
  ·
·3·                                                             ··ENTERGY
                                                                   ·      TEXAS, INC. (CONTINUED)
 ···
  ·APPLICATION OF ENTERGY· ··)· ·STATE OFFICE OF
·4·                                                            ·4·
                                                                 ·
 ··TEXAS,
    ·     INC., FOR· · · · ··)
  ·AUTHORITY TO CHANGE RATES )
·5·                                                             ···· ··CHRIS E. BARRILLEAUX
 ··AND
    ·  RECONCILE FUEL COSTS, )                                 ·5·
                                                                 · · · · · ·- Direct (Olson)· · · · · · · · · · · · · ·149
  ·AND OBTAIN DEFERRED· · · ·)
·6·
 ··ACCOUNTING
    ·         TREATMENT· · ··) ADMINISTRATIVE HEARINGS          ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·151
  ·
·7·                                                            ·6·
                                                                 · · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··167
 ···
  ·
·8·                                                             ···· · · · ·- Redirect (Olson)· · · · · · · · · · · · ·187
 ···                                                           ·7·
                                                                 · · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·198
  ·
·9·
 ···                                                           ·8·
                                                                 · · ··SAMUEL C. HADAWAY
  ·
10·                                                             ···· · · · ·- Direct (Williams)· · · · · · · · · · · ··199
 ···
  · · · · · · · · · ·HEARING ON THE MERITS
11·                                                            ·9·
                                                                 · · · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·201
 ···
  · · · · · · · · ·Thursday, April 26, 2012
12·                                                             ···· · · · ·- Cross (Griffiths)· · · · · · · · · · · ··212
 ···                                                           10·
                                                                 · · · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·230
  ·
13·
 ···                                                            ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··231
  ·
14·                                                            11·
                                                                 · · · · · ·- Recross (Griffiths)· · · · · · · · · · ··239
 ···
  · · · · · · · · · ··TABLE OF CONTENTS
15·                                                            12·
                                                                 ·PROCEEDINGS RECESSED· · · · · · · · · · · · · · · · ·246
 ···                                                           13·
                                                                 ·
  · · · ·(Volumes 1 through 3, Pages i through xxviii)
16·
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18·                                                            16·
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                                                    Page ii                                                       Page iv
·1·
  · · · · · · · ·TABLE OF CONTENTS                             ·1·
                                                                 · · · · · · · · ··TABLE OF CONTENTS
·2·
  · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE    ·2·
                                                                 · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE
·3·
  ·PROCEEDINGS, TUESDAY, APRIL 24, 2012 - VOL. 1· · · · ··5    ·3·
                                                                 ·PROCEEDINGS, WEDNESDAY, APRIL 25, 2012 - VOLUME 2· ··248
·4·
  ·OPENING STATEMENT ON BEHALF OF                              ·4·
                                                                 ·PRESENTATION ON BEHALF OF
 ··ENTERGY
    ·       TEXAS, INC. (Neinast)· · · · · · · · · · · · ·16    ··ENTERGY
                                                                   ·      TEXAS, INC. (CONTINUED)· · · · · · · · · · ··250
                                                               ·5·
                                                                 ·
·5·
  ·
                                                                ···· ··ROBERT D. SLOAN
 ··OPENING
    ·       STATEMENT ON BEHALF OF                             ·6·
                                                                 · · · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·250
·6·
  ·ENTERGY TEXAS, INC. (Wren)· · · · · · · · · · · · · ··22     ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·253
·7·
  ·OPENING STATEMENT ON BEHALF OF                              ·7·
                                                                 · · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·258
 ··CITIES
    ·      (Lawton)· · · · · · · · · · · · · · · · · · · ·37    ···· · · · ·- Redirect (Cyr)· · · · · · · · · · · · · ·285
·8·
  ·                                                            ·8·
                                                                 · · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·295
 ··OPENING
    ·       STATEMENT ON BEHALF OF                             ·9·
                                                                 · · ··H. VERNON PIERCE, JR.
·9·
  ·TEXAS INDUSTRIAL ENERGY CONSUMERS (VanMiddlesworth)· ·41     ···· · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·303
10·
  ·OPENING STATEMENT ON BEHALF OF                              10·
                                                                 · · · · · ·- Cross (Mack)· · · · · · · · · · · · · · ·305
 ··OFFICE
    ·      OF PUBLIC UTILITY COUNSEL (Ferris)· · · · · · ·49    ···· · · · ·- Cross (Younger)· · · · · · · · · · · · ··315
                                                               11·
                                                                 ·
11·
  ·
                                                                ···· ··MICHAEL P. CONSIDINE
 ··OPENING
    ·       STATEMENT ON BEHALF OF                             12·
                                                                 · · · · · ·- Direct (Neinast)· · · · · · · · · · · · ·317
12·
  ·STAFF (Smyth)· · · · · · · · · · · · · · · · · · · · ·52     ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·318
13·
  ·OPENING STATEMENT ON BEHALF OF                              13·
                                                                 · · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··352
 ··THE
    ·  UNITED STATES DEPARTMENT OF ENERGY (Porter)· · · ·54     ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·355
14·
  ·                                                            14·
                                                                 · · · · · ·- Redirect (Neinast)· · · · · · · · · · · ·358
15·
  ·PRESENTATION ON BEHALF OF                                    ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·362
 ··ENTERGY
    ·       TEXAS, INC.· · · · · · · · · · · · · · · · · ·60   15·
                                                                 ·
16·
  ·                                                             ··AFTERNOON
                                                                   ·        SESSION· · · · · · · · · · · · · · · · · ··365
 ···· ··JOSEPH DOMINO                                          16·
                                                                 ·
                                                                ··PRESENTATION
                                                                   ·           ON BEHALF OF
17·
  · · · · · ·- Direct (Wren)· · · · · · · · · · · · · · ·60    17·
                                                                 ·ENTERGY TEXAS, INC. (CONTINUED)· · · · · · · · · · ··366
 ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ··62    18·
                                                                 · · ··WALTER C. FERGUSON
18·
  ·                                                             ···· · · · ·- Direct (McNally)· · · · · · · · · · · · ·366
 ··AFTERNOON
    ·         SESSION· · · · · · · · · · · · · · · · · ··103   19·
                                                                 · · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·367
19·
  ·                                                             ···· · · · ·- Redirect (McNally)· · · · · · · · · · · ·369
 ··PRESENTATION
    ·            ON BEHALF OF                                  20·
                                                                 · · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·372
20·
  ·ENTERGY TEXAS, INC. (CONTINUED)                              ···· · · · ·- Further Redirect (McNally)· · · · · · · ·374
21·
  · · ··JOSEPH DOMINO                                          21·
                                                                 ·
 ···· · · · ·- Cross (Lawton - Continued)· · · · · · · ·103     ···· ··DANE A. WATSON
                                                               22·
                                                                 · · · · · ·- Direct (Williams)· · · · · · · · · · · ··376
22·
  · · · · · ·- Cross (VanMiddlesworth)· · · · · · · · ··115
                                                                ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·380
 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·131    23·
                                                                 · · · · · ·- Cross (Lawler)· · · · · · · · · · · · · ·397
23·
  · · · · · ·- Redirect (Wren)· · · · · · · · · · · · ··139     ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··403
 ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·143    24·
                                                                 · · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·410
24·
  · · · · · ·- Recross (VanMiddlesworth)· · · · · · · ··144     ···· · · · ·- Recross (Lawler)· · · · · · · · · · · · ·414
25·
  ·                                                            25·
                                                                 ·


                           KENNEDY REPORTING SERVICE, INC.
                                                 512.474.2233
                                                                                         Page 43 (Pages 681-684)
                                                              Page 681                                                              Page 683

·1·· ·here showed a cost of $1,100, an increase of $100 over             ·1·· · · · · · · · ·MR. VanMIDDLESWORTH:··Objection, as
·2·· ·Year 1 -- Year 1 to Year 3.··Do you see that?                      ·2·· ·leading.··I move to strike.
·3·· · · ·A· ··Yes.                                                      ·3·· · · · · · · · ·JUDGE BURKHALTER:··Sustained.
·4·· · · ·Q· ··Now, this is not rocket science.··Nobody will             ·4·· · · ·Q· ··BY MR. WESTERBURG)··Let me ask you this,
·5·· ·be surprised by the simplicity of this.··But if it's               ·5·· ·Mr. Cooper:··If you would clarify the record, what are
·6·· ·more, if the increase in capacity is actually greater              ·6·· ·the costs based on that appear in this chart?
·7·· ·than $1,100 -- say $1,300 -- because of the increase in            ·7·· · · ·A· ··The costs are based on the contracts between
·8·· ·capacity cost in Year 3, then under the chart that's               ·8·· ·ETI and the counter-parties and the rates that are
·9·· ·been developed by Mr. VanMiddlesworth, does the revenue            ·9·· ·established in those contracts.··So these would be
10·· ·of $1,100 cover the capacity cost?                                 10·· ·capacity costs associated with those contracts.··Reserve
11·· · · ·A· ··Not at that rate, no.                                     11·· ·equalization is also a part of the system agreement
12·· · · ·Q· ··All right.··I would like to also ask you --               12·· ·contract, and those costs will be incurred as part of
13·· ·maybe turn to the chart.··It's a pretty popular item --            13·· ·the system agreement expense.
14·· ·but I would like to ask you some questions about the               14·· · · ·Q· ··Does the calculation of the reserve
15·· ·Exhibit -- let's see.··I think it's TIEC Exhibit No.               15·· ·equalization have a load growth component?
16·· ·34 -- I think it's 34A.··It's the blow-up version --               16·· · · ·A· ··No, not really.··The reserve equalization
17·· · · · · · · · ·MR. WESTERBURG:··Is this 34 or 34A?··34A.            17·· ·includes a number of different elements associated with
18·· ·Excuse me.··I need to get my numbering straight for the            18·· ·it.··The two main elements are the amount of capability
19·· ·record here, Your Honor.                                           19·· ·each company brings to the system's load.··And the other
20·· · · ·Q· ··(BY MR. WESTERBURG)··I'm talking about the                20·· ·main ingredient is each company's responsibility ratio,
21·· ·blown-up version -- Mr. Cooper, you can look at the                21·· ·so the responsibility ratio as a percentage of the
22·· ·actual size document or you can look at the larger                 22·· ·system peak that each company shares.··And the extent
23·· ·document, which actually I find easier to look at, too,            23·· ·that a company is short -- in other words, they do not
24·· ·that Mr. VanMiddlesworth provided for us.                          24·· ·have enough capability to meet their requirements --
25·· · · ·A· ··I have it.                                                25·· ·then they would pay their responsibility ratio share of

                                                              Page 682                                                              Page 684

·1·· · · ·Q· ··And explain to us what this is.··What is this             ·1··  ·the excess from the long companies.
·2·· ·document?                                                          ·2··  · · ·Q· ··Now, the responsibility ratio that is the basis
·3·· · · ·A· ··This is a listing of contracts that ETI has                ·3·· ·of the reserve equalization on Line 25 --
·4·· ·entered into for the rate year, and it's divided up into            ·4·· · · ·A· ··Yes.
·5·· ·third-party contracts and Legacy affiliate contracts,               ·5·· · · ·Q· ··-- is that a projected responsibility ratio?
·6·· ·other affiliate contracts.··And then the last line item             ·6·· · · ·A· ··Yes, it is.··It's based on the projected loads
·7·· ·is reserve equalization.··These are contracts that have             ·7·· ·of all of the system companies during the rate year.
·8·· ·either been in place or will be coming on-line or new               ·8·· · · ·Q· ··Okay.··Now, are there any other numbers on this
·9·· ·contracts that have been entered into for the rate year.            ·9·· ·chart that are affected by a projected load?
10·· · · ·Q· ··Okay.··And I would like to ask you, Mr. Cooper,           10·· · · ·A· ··No, not that I'm aware of.
11·· ·these are capacity costs associated with those                     11·· · · ·Q· ··With respect to the reserve equalization, do
12·· ·contracts.··Is that right?                                         12·· ·you know what the result would be if, in fact, the
13·· · · ·A· ··Yes, that's correct.                                      13·· ·projected load you have in this exhibit were held
14·· · · ·Q· ··Now, are the costs that we're looking at here             14·· ·constant from the test year?
15·· ·projections or are they contractually based?                       15·· · · ·A· ··If we looked at the responsibility ratios of
16·· · · ·A· ··Well, they are contractually based projections            16·· ·each of the companies during the test year and we
17·· ·of what the costs will be.··So, you know, there are                17·· ·applied it to these contracts and rates, the reserve
18·· ·terms and conditions associated with delivery on these             18·· ·equalization would be about four and a half million
19·· ·contracts that, you know, if someone fails to deliver,             19·· ·dollars less for ETI.
20·· ·there may be penalties associated with the third-party             20·· · · ·Q· ··Now, there was a lot of talk about the EAI WBL,
21·· ·contracts.··But in general, they are contractually                 21·· ·and that contract is reflected on Line 19.
22·· ·based.                                                             22·· · · ·A· ··Yes.
23·· · · ·Q· ··Right.··In other words, they are charges that             23·· · · ·Q· ··To clarify for the Judges -- to the extent they
24·· ·the company will have to pay?                                      24·· ·may need it; they may not -- but for the record, the
25·· · · ·A· ··Yes.                                                      25·· ·discussion about the operating committee minutes for


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·1·· ·what may have been referred to as a new WBL contract,             ·1··  · · ·A· ··Yes.
·2·· ·when does that contract that is made the discussion of            ·2··  · · ·Q· ··Mr. Cooper, now the chart we're looking at
·3·· ·the operating committee minutes, when does that contract           ·3·· ·here, this is a revision.··Is that correct?
·4·· ·begin?··And if you could refer us to the chart.                    ·4·· · · ·A· ··Yes, it is.
·5·· · · ·A· ··The contract that was approved by the operating           ·5·· · · ·Q· ··Okay.··And was the revision for the purpose of
·6·· ·committee in mid-March actually goes into effect in                ·6·· ·reflecting the new WBL contract in January 2013?
·7·· ·January of 2013.                                                   ·7·· · · ·A· ··Yes, it was.
·8·· · · ·Q· ··Okay.··So what do we have represented for the             ·8·· · · ·Q· ··Now, in the lower right-hand corner, the number
·9·· ·EAI WBL on Line 19, prior to January 13?                           ·9·· ·that is $275,800,000 and some additional dollars, I
10·· · · ·A· ··That's the existing EAI WBL contract.                    10·· ·believe that's the total capacity charges that's
11·· · · ·Q· ··Okay.··Do you recall when the case was filed in          11·· ·indicated on the chart.··Does that represent a total of
12·· ·this docket, Mr. Cooper?··I'm just asking.                        12·· ·all the charges on this chart?
13·· · · ·A· ··In November.                                             13·· · · ·A· ··Yes.
14·· · · ·Q· ··Right.··November.··And I see here that the               14·· · · ·Q· ··Okay.··Now, can you tell us whether or not that
15·· ·first date entry or the first month entry for this chart          15·· ·number that appears on your revised RRC-1 is higher or
16·· ·is June 12.··Do you see that?                                     16·· ·lower than the number that was there prior to the
17·· · · ·A· ··Yes, I do.                                               17·· ·revision?
18·· · · ·Q· ··Is it your understanding that that's the                 18·· · · ·A· ··It's lower by about $400,000.
19·· ·beginning of what we refer to as the rate year?                   19·· · · ·Q· ··Now, was that --
20·· · · ·A· ··Yes, that is.                                            20·· · · · · · · · ·JUDGE ARNOLD:··Mr. Westerburg, you're
21·· · · ·Q· ··So was the company -- and were you, Mr. Cooper,          21·· ·getting into specific numbers.··Are those highly
22·· ·when you prepared this chart, projecting future cost?             22·· ·sensitive?
23·· · · · · · · · ·JUDGE BURKHALTER:··For what time period?            23·· · · · · · · · ·MR. WESTERBURG:··The totals, Your Honor,
24·· · · · · · · · ·MR. WESTERBURG:··Thank you.                         24·· ·are not.··But I appreciate the warning.··Thank you.
25·· · · ·Q· ··(BY MR. WESTERBURG)··For the rate year.                  25·· · · ·Q· ··(BY MR. WESTERBURG)··And can you tell us,

                                                             Page 686                                                        Page 688

·1·· · · ·A· ··The EAI WBL, the contract that existed, that             ·1··  ·Mr. Cooper, if that is attributable in part or in whole
·2·· ·was a projection of the MSS-4 costs associated with the           ·2··  ·to the new WBL contract?
·3·· ·existing contract, yes.                                            ·3·· · · ·A· ··That's the $400,000?
·4·· · · ·Q· ··How does the projection of the capacity cost              ·4·· · · ·Q· ··Yes, the reduction in cost.
·5·· ·for your RRC-1, for the EAI WBL, how does that compare             ·5·· · · ·A· ··Yes, that would be attributable to the change
·6·· ·to the projection of cost beginning in January '13 for             ·6·· ·in the WBL contract.
·7·· ·the EAI WBL, in terms of the way that it was developed?            ·7·· · · ·Q· ··What are the megawatts associated with the new
·8·· · · ·A· ··The way it was developed was similar.··We used            ·8·· ·contract, beginning in January 2013?
·9·· ·a similar process to develop that.··The resources that             ·9·· · · ·A· ··It's 186 megawatts.
10·· ·make up the new contract do not include two of the                10·· · · ·Q· ··And what were the megawatts associated with the
11·· ·nuclear units that Arkansas has.                                  11·· ·existing contract that runs through the end of this
12·· · · · · · · · ·So we eliminated those two resources from           12·· ·year?
13·· ·the WBL, and we then changed the megawatt amount,                 13·· · · ·A· ··I believe it was 110 megawatts.
14·· ·because the total megawatts that ETI is going to be               14·· · · ·Q· ··As a result of the new WBL, is the company and
15·· ·receiving from this new contract has increased from               15·· ·customers receiving greater megawatts at a lesser cost?
16·· ·110 megawatts to 186 megawatts.··So we applied the new            16·· · · ·A· ··Yes, they are.
17·· ·megawatts and the rates that were the same from the               17·· · · ·Q· ··Are you aware of any -- back up, lay a
18·· ·existing contract, to the resources that are part of the          18·· ·predicate.··Have you reviewed the intervenors' testimony
19·· ·new WBL contract.                                                 19·· ·on the issue of the EAI WBL?
20·· · · ·Q· ··Did the projections prior to January of 2013,            20·· · · ·A· ··Yes, I have.
21·· ·were they based on the MSS-4 rate of the system                   21·· · · ·Q· ··Are you aware of any objections to the
22·· ·agreement?                                                        22·· ·projected cost of the existing EAI WBL?
23·· · · ·A· ··Yes.                                                     23·· · · ·A· ··No, I'm not.
24·· · · ·Q· ··The projections after January of 2013, were              24·· · · · · · · · ·JUDGE BURKHALTER:··When you say
25·· ·they based on the MMS-4 of the system agreement?                  25·· ·"existing," are you talking about the original one?··I'm


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·1·· ·not sure I'm following you.                                       ·1··  ·operating committee minutes.··Do you recall that?
·2·· · · · · · · · ·MR. WESTERBURG:··I'll ask the witness,              ·2··  · · ·A· ··Yes, I do.
·3·· ·Your Honor.                                                        ·3·· · · ·Q· ··And my questions will be directed toward the
·4·· · · ·Q· ··(BY MR. WESTERBURG)··Can you clarify for us the           ·4·· ·February operating committee minutes.··And you
·5·· ·meaning of "existing"?                                             ·5·· ·understand the distinction?
·6·· · · ·A· ··The existing contract that goes through the end           ·6·· · · ·A· ··Yes.
·7·· ·of 2012.                                                           ·7·· · · ·Q· ··Are you familiar with the processes of the
·8·· · · ·Q· ··And, Mr. Cooper, is that the contract                     ·8·· ·operating committee?
·9·· ·associated with the numbers -- well, let me just ask               ·9·· · · ·A· ··I'm somewhat familiar with the processes, not
10·· ·you:··What numbers on this chart are associated with              10·· ·intimately familiar.
11·· ·what we refer to as the existing EAI WBL?                         11·· · · ·Q· ··Have you had an experience with there being
12·· · · ·A· ··Those would be Line 19, June through December            12·· ·delays of the finality of presentations with operating
13·· ·of 2012.                                                          13·· ·committee minutes?
14·· · · ·Q· ··Now, this MSS-4 tariff, do you know whether              14·· · · ·A· ··Yes.··As I mentioned, it typically takes at
15·· ·that is part of what's referred to as the Energy System           15·· ·least a month to get the minutes from the operating
16·· ·Agreement?                                                        16·· ·committee subsequent to the actual meeting.
17·· · · ·A· ··Yes.··MSS-4 is a schedule in the system                  17·· · · ·Q· ··Do you know whether or not the operating
18·· ·agreement.                                                        18·· ·committee sometimes requests changes to those
19·· · · ·Q· ··Does the company have any discretion in the way          19·· ·presentations?
20·· ·it bills under that tariff?                                       20·· · · ·A· ··No, I do not.
21·· · · ·A· ··No.··That's a FERC-regulated tariff that the             21·· · · ·Q· ··Do you know -- I'm looking for the contract.
22·· ·company really has no discretion in how it bills.                 22·· ·And I'm going to refer to the exhibit marked as TIEC
23·· · · ·Q· ··Do you know if there have been changes to that           23·· ·Exhibit No. 21.
24·· ·tariff -- scratch that and start again.··Do you know              24·· · · ·A· ··Yes, I have it.
25·· ·whether there will be changes to that tariff between now          25·· · · ·Q· ··Right now, is this also an exhibit that's made

                                                             Page 690                                                                Page 692

·1·· ·and the time that the company implements the new WBL              ·1·· ·an exhibit to your rebuttal testimony?
·2·· ·contract in January 2013?                                         ·2·· · · ·A· ··Yes, it is.
·3·· · · ·A· ··No, I'm unaware of any changes.                          ·3·· · · ·Q· ··And what is it that we're looking at here,
·4·· · · ·Q· ··There was a discussion about the volatility of           ·4·· ·Exhibit 21?
·5·· ·fuel cost, Mr. Cooper.··Is it your experience that the            ·5·· · · ·A· ··This is the agreement between ETI and EAI for
·6·· ·cost of gas is volatile?                                          ·6·· ·the WBL contract that begins in 2013.
·7·· · · ·A· ··Yes.··The cost of gas, as recently as several            ·7·· · · ·Q· ··Do you have any knowledge, Mr. Cooper,
·8·· ·years ago, was $14 a million Btu.··And, you know, in              ·8·· ·regarding whether there are or are not negotiations
·9·· ·recent weeks it's been two dollars a million Btu.··It             ·9·· ·related to the signing of these kinds of agreements?
10·· ·goes up; it goes down.                                            10·· · · ·A· ··No, I do not.
11·· · · ·Q· ··Has it been your experience that it has gone up          11·· · · ·Q· ··Let me take you to Page 2 of the agreement.
12·· ·and down over relatively short periods of time?                   12·· ·There is a page number in the lower right-hand corner
13·· · · ·A· ··It has gone up and down over short periods of            13·· ·that is 25.
14·· ·time, too.                                                        14·· · · ·A· ··Yes, I'm there.
15·· · · ·Q· ··How does the volatility of gas cost compare to           15·· · · ·Q· ··Now, would you read Section 6.
16·· ·the volatility of cost associated with the resources in           16·· · · ·A· ··Yes.··"Condition Precedent.··This Agreement
17·· ·the new WBL contract?                                             17·· ·shall be conditioned upon Buyer receiving all regulatory
18·· · · ·A· ··Well, gas historically has been much more                18·· ·approvals required by Buyer for this Agreement no later
19·· ·volatile than coal and nuclear fuel.··Nuclear fuel is             19·· ·than August 1, 2012."
20·· ·typically procured on long-term contracts; coal is also           20·· · · ·Q· ··And who is the buyer here?
21·· ·typically procured on long-term contracts.··And so the            21·· · · ·A· ··That would be Entergy Texas.
22·· ·price of those two fuels has been relatively stable over          22·· · · ·Q· ··Okay.··Do you know whether the operating
23·· ·the past.                                                         23·· ·committee has made any indication of whether this
24·· · · ·Q· ··Now, there was some discussion also,                     24·· ·contract will go forward for Entergy Texas if, in fact,
25·· ·Mr. Cooper, about the timing of the production of the             25·· ·it turns out that the Commission did not approve the


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·1·· ·contract?                                                         ·1··  ·understanding of what is before the Commission that is
·2·· · · ·A· ··No, I'm not aware.                                        ·2· ·available for the review of the operating committee's
                                                                            ·
·3·· · · ·Q· ··There was a discussion about hedging,                     ·3·· ·decision regarding the EAI WBL in this case?
·4·· ·Mr. Cooper.··Rather than to try to capture what                    ·4·· · · ·A· ··The operating committee minutes and the
·5·· ·you said -- and I don't think I'll do a good job of                ·5·· ·presentations associated with it and the contract
·6·· ·it -- would you state again your understanding of the              ·6·· ·associated with the new WBL.
·7·· ·practice or the opportunities for hedging as they may be           ·7·· · · ·Q· ··In Mr. VanMiddlesworth's cross-examination of
·8·· ·exercised by Entergy Services on behalf of the operating           ·8·· ·you on that?
·9·· ·companies and the Texas Commission, the PUCT's position,           ·9·· · · ·A· ··Yes.
10·· ·your understanding of that.                                       10·· · · ·Q· ··To clarify a timing issue, if you could look at
11·· · · ·A· ··Yes.··I know that in the State of Louisiana and          11·· ·the exhibit that is the MSS-4 contract.
12·· ·the State of Mississippi, the utilities there practice a          12·· · · ·A· ··Yes, I have it here.
13·· ·gas hedging program where they fix forward a portion of           13·· · · ·Q· ··Now, what is the date at the top of the
14·· ·their projected requirements in order to reduce the               14·· ·contract that the contract is dated?
15·· ·volatility of gas supply costs.··And it was my                    15·· · · ·A· ··This agreement is dated as of April 11, 2012.
16·· ·understanding that we have proposed a similar hedging             16·· · · ·Q· ··Okay.··And it will be obvious from the record,
17·· ·program in Texas, and it was denied.                              17·· ·but do you recall whether or not the operating
18·· · · ·Q· ··Are you aware of any intervenors proposing               18·· ·committee's decision approving this contract was
19·· ·hedging in this case?                                             19·· ·provided in this case prior to this date?
20·· · · ·A· ··No.                                                      20·· · · ·A· ··Yes, that's my understanding.
21·· · · ·Q· ··You mentioned your knowledge or your belief              21·· · · ·Q· ··Okay.··Mr. Cooper, with regard to
22·· ·that there was a proposal by the company.··Do you know            22·· ·Mr. VanMiddlesworth's chart up here, is it your
23·· ·whether or not either the Staff or any intervening party          23·· ·understanding that only capacity charges are reflected?
24·· ·has ever proposed hedging for Texas?                              24·· ·Is there an energy cost reflected?
25·· · · ·A· ··No, I'm not aware.                                       25·· · · ·A· ··The only charges that Mr. VanMiddlesworth

                                                             Page 694                                                                Page 696
·1·· · · ·Q· ··Back to EAI WBL -- sorry for jumping around --           ·1·· ·reflects are capacity charges, and then he tries to
·2·· ·but there is an existing EAI WBL in place.··Correct?              ·2·· ·allocate those across Entergy.··And, you know, as
·3·· · · ·A· ··Yes, that's correct.                                     ·3·· ·associated with these contracts, you know, many of these
·4·· · · ·Q· ··And do you know how long the term is of that             ·4·· ·contracts are actually going to provide lower cost
·5·· ·one -- not when it ends.··I know it ends in December.             ·5·· ·energy than would be available from existing resources
·6·· ·We saw that.                                                      ·6·· ·or if they were just to rely on the resources of the
·7·· · · ·A· ··Yes.··I believe that was a three-year                    ·7·· ·reserves of the Entergy system.
·8·· ·agreement.                                                        ·8·· · · · · · · · ·In addition, these capacity charges assume
·9·· · · ·Q· ··Okay.··Was there an EAI WBL in place under               ·9·· ·that they are incremental.··And in the case of ETI being
10·· ·which Texas received or Entergy Texas or its predecessor          10·· ·a short company, we're not even getting ETI up to their
11·· ·received capacity prior to that?                                  11·· ·capacity needs.··And so, you know, I don't even consider
12·· · · ·A· ··I don't recall.                                          12·· ·these capacity charges incremental.··They're just, you
13·· · · · · · · · ·(Brief pause)                                       13·· ·know, trying to bring them up to the level that they
14·· · · · · · · · ·MR. WESTERBURG:··Your Honor, I'm trying to          14·· ·need to be, because they're short on resources.
15·· ·weed out questions, so if you'll bear with me.                    15·· · · ·Q· ··Let me ask you about that, Mr. Cooper.··If you
16·· · · · · · · · ·JUDGE BURKHALTER:··Thank you.··I                    16·· ·would go back to your RRC-1 --
17·· ·appreciate it.                                                    17·· · · ·A· ··Yes.
18·· · · ·Q· ··(BY MR. WESTERBURG)··Mr. Cooper, I think toward          18·· · · ·Q· ··-- now, are there new third-party contracts
19·· ·the end of Mr. VanMiddlesworth's cross-examination, you           19·· ·that are in place for the rate year that were not in
20·· ·made a reference to all files regarding the EAI WBL as            20·· ·place for the test year?
21·· ·being the basis -- being available for the                        21·· · · ·A· ··Yes.
22·· ·Commission's review.··Do you remember your comment on             22·· · · ·Q· ··And which ones are those?
23·· ·files?                                                            23·· · · ·A· ··Well, we have Calpine-Carville and SRMPA.
24·· · · ·A· ··No.                                                      24·· · · ·Q· ··And if you could tell us the line number, just
25·· · · ·Q· ··I may be remembering wrong.··What is your                25·· ·so we --


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·1··  ·has various provisions for required availability rates         ·1·· · · ·A· ··I don't know.
·2··  ·and other things that affect what gets actually paid.          ·2·· · · ·Q· ··Did ETI experience load growth in the two years
 ·3·· ·Correct?                                                       ·3·· ·between the last test year and this test year?
 ·4·· · · ·A· ··That's correct, yes.                                  ·4·· · · ·A· ··I don't know.
 ·5·· · · ·Q· ··And what do you assume for disallowances for          ·5·· · · ·Q· ··Were you here for Mr. Domino's testimony the
 ·6·· ·availability factor adjustments in this?                       ·6·· ·other day?
 ·7·· · · ·A· ··We did not assume anything.                           ·7·· · · ·A· ··No, I wasn't.
 ·8·· · · ·Q· ··But there have been adjustments in the past           ·8·· · · ·Q· ··So this no-load-growth scenario that results in
 ·9·· ·years for availability, haven't there?                         ·9·· ·an underrecovery, that's not what ETI is projecting, is
10·· · · ·A· ··Yes, there have, and they have been relatively         10·· ·it?
11·· ·minor.                                                          11·· · · ·A· ··No.
12·· · · ·Q· ··And for the -- well, let's pick another one.           12·· · · ·Q· ··Now let me refer you to Exhibit 19.··I wanted
13·· ·For the ConocoPhillips -- I guess that's the SRW                13·· ·to clarify some things that Mr. Westerburg asked.
14·· ·contract -- that also has various provisions for                14·· ·Exhibit 19A is this sensitive material.··Do you have
15·· ·performance and for reducing the payment based on that.         15·· ·that?
16·· ·Correct?                                                        16·· · · · · · · · ·MR. WESTERBURG:··I'm sorry.··Exhibit 19A,
17·· · · ·A· ··Yes, that's correct.                                   17·· ·which one is that, so I can look it up?
18·· · · ·Q· ··And in the Line 1, you didn't assume that the          18·· · · · · · · · ·MR. VanMIDDLESWORTH:··That's the March 23,
19·· ·payment would be reduced at all for that?                       19·· ·2012 copy of the February 17 operating committee meeting
20·· · · ·A· ··Yes, that's correct.                                   20·· ·minutes.
21·· · · ·Q· ··Okay.··And we won't know until the actual year         21·· · · · · · · · ·MR. WESTERBURG:··Got it.
22·· ·comes and goes.··Right?                                         22·· · · · · · · · ·JUDGE BURKHALTER:··And are you intending
23·· · · ·A· ··Yes, sir.                                              23·· ·to go into highly sensitive?
24·· · · ·Q· ··You talked about lower fuel costs associated           24·· · · · · · · · ·MR. VanMIDDLESWORTH:··I'm not.
25·· ·with some of these contracts.··The fuel costs flow              25·· · · · · · · · ·JUDGE BURKHALTER:··Okay.

                                                           Page 706                                                                   Page 708

·1·· ·through the fuel factor.··Isn't that right?                     ·1·· · · ·A· ··Yes, sir, I have it.
·2·· · · ·A· ··Yes, sir.                                              ·2·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··All right.··Now,
·3·· · · ·Q· ··And Entergy receives its actual reasonable fuel        ·3·· ·first of all, turning to the page that's marked TH794.
·4·· ·costs from ratepayers -- no more, no less.··Correct?            ·4·· ·Do you see that?··Under "Item 3 -- 2013 EAI Wholesale
·5·· · · ·A· ··It's subject to reconciliation in Texas, yes.          ·5·· ·Baseload, (Attachment C)"?
·6·· · · ·Q· ··And are you suggesting that you ought to               ·6·· · · ·A· ··I'm afraid my pages got messed up here.
·7·· ·overrecover your actual capacity charges if you lower           ·7·· · · · · · · · ·MR. VanMIDDLESWORTH:··May I approach the
·8·· ·fuel costs?                                                     ·8·· ·witness, Your Honor?
·9·· · · ·A· ··No, I'm not.                                           ·9·· · · · · · · · ·JUDGE BURKHALTER:··Yes.
10·· · · ·Q· ··So you're still believing you should only              10·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··You can look at mine.
11·· ·recover your actual capacity charge?                            11·· · · ·A· ··Is that it, 794?
12·· · · ·A· ··I'm suggesting we should recover the costs that        12·· · · ·Q· ··Yes.
13·· ·we incur for our capacity transactions.                         13·· · · ·A· ··Okay.
14·· · · ·Q· ··All right.··And even if they reduce fuel costs,        14·· · · ·Q· ··You see Item 3 refers to 2013 EAI wholesale
15·· ·you don't get more than your actual costs.··Right?              15·· ·baseload?··And it says Attachment C?
16·· · · ·A· ··I'm sorry.··I don't understand that question.          16·· · · ·A· ··Yes.
17·· · · ·Q· ··Well, it's probably my fault.··Let me ask about        17·· · · ·Q· ··And then the next line says Charles DeGeorge
18·· ·this chart, ETI Exhibit 7, for you.··You were asked what        18·· ·provided the Committee members with a wholesale baseload
19·· ·would happen if there were no load growth between Year 1        19·· ·sales analysis?
20·· ·and Year 3 here.··Do you recall that?                           20·· · · ·A· ··Yes.
21·· · · ·A· ··Yes.                                                   21·· · · ·Q· ··Now, let me ask you to turn to Page 858 of TIEC
22·· · · ·Q· ··Does ETI project load growth between the test          22·· ·Exhibit 19A.
23·· ·year and the rate year?                                         23·· · · ·A· ··It's stuck in here.
24·· · · ·A· ··Yes, they do.                                          24·· · · ·Q· ··All right.··Let me show you mine.··I refer you
25·· · · ·Q· ··How much?                                              25·· ·to Page 858 --


                                KENNEDY REPORTING SERVICE, INC.
                                                           512.474.2233
                                                                                       Page 1 (Pages 1-4)
                                                     Page i                                                      Page iii
  · · · · · · · ··SOAH DOCKET NO. XXX-XX-XXXX
·1·                                                            ·1·
                                                                 · · · · · · · ·TABLE OF CONTENTS (CONTINUED)
 ···                                                           ·2·
                                                                 · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE
  · · · · · · · · · ·PUC DOCKET NO. 39896
·2·
 ···                                                           ·3·
                                                                 ·PRESENTATION ON BEHALF OF
  ·
·3·                                                             ··ENTERGY
                                                                   ·      TEXAS, INC. (CONTINUED)
 ···
  ·APPLICATION OF ENTERGY· ··)· ·STATE OFFICE OF
·4·                                                            ·4·
                                                                 ·
 ··TEXAS,
    ·     INC., FOR· · · · ··)
  ·AUTHORITY TO CHANGE RATES )
·5·                                                             ···· ··CHRIS E. BARRILLEAUX
 ··AND
    ·  RECONCILE FUEL COSTS, )                                 ·5·
                                                                 · · · · · ·- Direct (Olson)· · · · · · · · · · · · · ·149
  ·AND OBTAIN DEFERRED· · · ·)
·6·
 ··ACCOUNTING
    ·         TREATMENT· · ··) ADMINISTRATIVE HEARINGS          ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·151
  ·
·7·                                                            ·6·
                                                                 · · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··167
 ···
  ·
·8·                                                             ···· · · · ·- Redirect (Olson)· · · · · · · · · · · · ·187
 ···                                                           ·7·
                                                                 · · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·198
  ·
·9·
 ···                                                           ·8·
                                                                 · · ··SAMUEL C. HADAWAY
  ·
10·                                                             ···· · · · ·- Direct (Williams)· · · · · · · · · · · ··199
 ···
  · · · · · · · · · ·HEARING ON THE MERITS
11·                                                            ·9·
                                                                 · · · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·201
 ···
  · · · · · · · · ··Friday, April 27, 2012
12·                                                             ···· · · · ·- Cross (Griffiths)· · · · · · · · · · · ··212
 ···                                                           10·
                                                                 · · · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·230
  ·
13·
 ···                                                            ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··231
  ·
14·                                                            11·
                                                                 · · · · · ·- Recross (Griffiths)· · · · · · · · · · ··239
 ···
  · · · · · · · · · ··TABLE OF CONTENTS
15·                                                            12·
                                                                 ·PROCEEDINGS RECESSED· · · · · · · · · · · · · · · · ·246
 ···                                                           13·
                                                                 ·
  · · · ·(Volumes 1 through 4, Pages i through xxxii)
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                                                    Page ii                                                       Page iv
·1·
  · · · · · · · ·TABLE OF CONTENTS                             ·1·
                                                                 · · · · · · · · ··TABLE OF CONTENTS
·2·
  · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE    ·2·
                                                                 · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE
·3·
  ·PROCEEDINGS, TUESDAY, APRIL 24, 2012 - VOL. 1· · · · ··5    ·3·
                                                                 ·PROCEEDINGS, WEDNESDAY, APRIL 25, 2012 - VOLUME 2· ··248
·4·
  ·OPENING STATEMENT ON BEHALF OF                              ·4·
                                                                 ·PRESENTATION ON BEHALF OF
 ··ENTERGY
    ·       TEXAS, INC. (Neinast)· · · · · · · · · · · · ·16    ··ENTERGY
                                                                   ·      TEXAS, INC. (CONTINUED)· · · · · · · · · · ··250
                                                               ·5·
                                                                 ·
·5·
  ·
                                                                ···· ··ROBERT D. SLOAN
 ··OPENING
    ·       STATEMENT ON BEHALF OF                             ·6·
                                                                 · · · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·250
·6·
  ·ENTERGY TEXAS, INC. (Wren)· · · · · · · · · · · · · ··22     ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·253
·7·
  ·OPENING STATEMENT ON BEHALF OF                              ·7·
                                                                 · · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·258
 ··CITIES
    ·      (Lawton)· · · · · · · · · · · · · · · · · · · ·37    ···· · · · ·- Redirect (Cyr)· · · · · · · · · · · · · ·285
·8·
  ·                                                            ·8·
                                                                 · · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·295
 ··OPENING
    ·       STATEMENT ON BEHALF OF                             ·9·
                                                                 · · ··H. VERNON PIERCE, JR.
·9·
  ·TEXAS INDUSTRIAL ENERGY CONSUMERS (VanMiddlesworth)· ·41     ···· · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·303
10·
  ·OPENING STATEMENT ON BEHALF OF                              10·
                                                                 · · · · · ·- Cross (Mack)· · · · · · · · · · · · · · ·305
 ··OFFICE
    ·      OF PUBLIC UTILITY COUNSEL (Ferris)· · · · · · ·49    ···· · · · ·- Cross (Younger)· · · · · · · · · · · · ··315
                                                               11·
                                                                 ·
11·
  ·
                                                                ···· ··MICHAEL P. CONSIDINE
 ··OPENING
    ·       STATEMENT ON BEHALF OF                             12·
                                                                 · · · · · ·- Direct (Neinast)· · · · · · · · · · · · ·317
12·
  ·STAFF (Smyth)· · · · · · · · · · · · · · · · · · · · ·52     ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·318
13·
  ·OPENING STATEMENT ON BEHALF OF                              13·
                                                                 · · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··352
 ··THE
    ·  UNITED STATES DEPARTMENT OF ENERGY (Porter)· · · ·54     ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·355
14·
  ·                                                            14·
                                                                 · · · · · ·- Redirect (Neinast)· · · · · · · · · · · ·358
15·
  ·PRESENTATION ON BEHALF OF                                    ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·362
 ··ENTERGY
    ·       TEXAS, INC.· · · · · · · · · · · · · · · · · ·60   15·
                                                                 ·
16·
  ·                                                             ··AFTERNOON
                                                                   ·        SESSION· · · · · · · · · · · · · · · · · ··365
 ···· ··JOSEPH DOMINO                                          16·
                                                                 ·
                                                                ··PRESENTATION
                                                                   ·           ON BEHALF OF
17·
  · · · · · ·- Direct (Wren)· · · · · · · · · · · · · · ·60    17·
                                                                 ·ENTERGY TEXAS, INC. (CONTINUED)· · · · · · · · · · ··366
 ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ··62    18·
                                                                 · · ··WALTER C. FERGUSON
18·
  ·                                                             ···· · · · ·- Direct (McNally)· · · · · · · · · · · · ·366
 ··AFTERNOON
    ·         SESSION· · · · · · · · · · · · · · · · · ··103   19·
                                                                 · · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·367
19·
  ·                                                             ···· · · · ·- Redirect (McNally)· · · · · · · · · · · ·369
 ··PRESENTATION
    ·            ON BEHALF OF                                  20·
                                                                 · · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·372
20·
  ·ENTERGY TEXAS, INC. (CONTINUED)                              ···· · · · ·- Further Redirect (McNally)· · · · · · · ·374
21·
  · · ··JOSEPH DOMINO                                          21·
                                                                 ·
 ···· · · · ·- Cross (Lawton - Continued)· · · · · · · ·103     ···· ··DANE A. WATSON
                                                               22·
                                                                 · · · · · ·- Direct (Williams)· · · · · · · · · · · ··376
22·
  · · · · · ·- Cross (VanMiddlesworth)· · · · · · · · ··115
                                                                ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·380
 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·131    23·
                                                                 · · · · · ·- Cross (Lawler)· · · · · · · · · · · · · ·397
23·
  · · · · · ·- Redirect (Wren)· · · · · · · · · · · · ··139     ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··403
 ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·143    24·
                                                                 · · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·410
24·
  · · · · · ·- Recross (VanMiddlesworth)· · · · · · · ··144     ···· · · · ·- Recross (Lawler)· · · · · · · · · · · · ·414
25·
  ·                                                            25·
                                                                 ·


                           KENNEDY REPORTING SERVICE, INC.
                                                 512.474.2233
                                                                                       Page 2 (Pages 723-726)
                                                     Page 723                                                                   Page 725

·1··  ·subject to the prior ruling on objections to ETI Exhibit   ·1··  ·sorry -- other -- let me rephrase that.··Too many MSSs.
·2··  ·No. 39, it is admitted.                                    ·2··  · · · · · · · ·You also support the system agreement
 ·3·· · · · · · · · ·(Exhibit ETI No. 39 admitted)                 ·3·· ·costs in the fuel reconciliation period to the extent
 ·4·· · · · · · · · ·MR. WESTERBURG:··Your Honor, ETI tenders      ·4·· ·they're included there?
 ·5·· ·the witness for cross.                                      ·5·· · · ·A· ··Yes, I support the other service schedule
 ·6·· · · · · · · · ·JUDGE WALSTON:··All right.··Cities?           ·6·· ·costs, whether they're in the fuel part or in base rates
 ·7·· · · · · · · · ·MR. LAWTON:··Yes, Your Honor.··May I          ·7·· ·in this case.
 ·8·· ·begin?                                                      ·8·· · · ·Q· ··But to be clear, you support the test year
 ·9·· · · · · · · · ·JUDGE WALSTON:··Yes.                          ·9·· ·costs, whatever they were, about 1.7 million.··Correct?
10·· · · · · · · · ·MR. LAWTON:··Thank you.                       10·· · · ·A· ··Are we talking about my direct testimony or are
11·· · · · · · · · · · · ·CROSS-EXAMINATION                       11·· ·we talking about my rebuttal testimony in this?
12·· ·BY MR. LAWTON:                                              12·· · · ·Q· ··It's my understanding you're only here for
13·· · · ·Q· ··Good morning, Mr. Cicio.··How are you, sir?        13·· ·direct today.
14·· · · ·A· ··Good morning, Mr. Lawton.··Just fine.              14·· · · ·A· ··Okay.··In this particular case, Mr. Considine
15·· · · ·Q· ··Okay.··Start off with Page 3, Line 20 of your      15·· ·supported the pro forma to the test year MSS-2 costs in
16·· ·testimony, which is, I think -- ETI Exhibit 39, Is it?      16·· ·this case.
17·· · · ·A· ··Page 3 --                                          17·· · · ·Q· ··Okay.··He supported a 9 million-dollar pro
18·· · · ·Q· ··Line 20.                                           18·· ·forma in MSS-2 costs.··Correct?
19·· · · ·A· ··-- Line 20.··Okay.                                 19·· · · ·A· ··The total was 10.7 million for the pro forma,
20·· · · ·Q· ··Okay.··Now, I want to understand the purpose of    20·· ·as I recall.
21·· ·your testimony and exactly what you do.                     21·· · · ·Q· ··And when I asked him about the basis for that
22·· · · · · · · · ·The first thing I see there is you support    22·· ·9 million-dollar adjustment the other day, Mr. Considine
23·· ·the costs and revenues associated with ETI's                23·· ·told me he got it from, I think, your group.
24·· ·participation in the Entergy service agreement during       24·· · · ·A· ··Okay.··That's what he testified.··I haven't
25·· ·the test year, July 1, 2010 to June 30, 2011.··Correct?     25·· ·read Mr. Considine's testimony.

                                                     Page 724                                                                   Page 726

·1··  · · ·A· ··It's the Entergy system agreement, yes.           ·1·· · · ·Q· ··He got it from some accounting group that does
·2··  · · ·Q· ··Okay.··And so when you say you support the        ·2·· ·this work, MSS-2.··Would that be your group or can you
 ·3·· ·costs and revenues associated with the service             ·3·· ·think of somebody else?
 ·4·· ·agreement, what costs and revenues are you talking         ·4·· · · ·A· ··He got that information from a combination of
 ·5·· ·about?                                                     ·5·· ·sources.··I think it was looked at by my group as well.
 ·6·· · · ·A· ··I think I go through and list those in my         ·6·· · · ·Q· ··Well, I'm wondering, who do I ask questions
 ·7·· ·testimony, but generally speaking, it's the MSS-1          ·7·· ·about the 10.6 million calculation?
 ·8·· ·service -- Schedule MSS-1, MSS-2, MSS-3, MSS-5 and I       ·8·· · · · · · · · ·In this direct case, I've asked
 ·9·· ·think that's it -- and MSS-4.··I think I forgot that.      ·9·· ·Mr. Considine about it, and now I'm asking you about it.
10·· · · ·Q· ··Okay.··And if we -- and we're going to focus a     10·· ·And you don't testify to the 10.6 million.··Who in this
11·· ·bit today on what's called MSS-2.                           11·· ·case testifies to the 10.6 million of MSS-2 costs the
12·· · · · · · · · ·So would you tell us what MSS-2 is?           12·· ·company is requesting in this direct case?
13·· · · ·A· ··Generally speaking, MSS-2 is the service           13·· · · · · · · · ·Who does it?··Who do I ask?
14·· ·schedule by which certain transmissions costs are           14·· · · ·A· ··It depends on what component of the
15·· ·equalized among the operating companies, and it's the       15·· ·calculations you're talking about.··The investment, I
16·· ·ownership costs of those transmission assets.               16·· ·believe, was sponsored -- or was supported by
17·· · · ·Q· ··And as I understand it, you support the test       17·· ·Mr. McCulla's organization.··The calculation was done in
18·· ·year cost of MSS-2?                                         18·· ·another group, but, you know, my group reviewed that.
19·· · · ·A· ··In my testimony, I support the test year cost      19·· ·So I feel comfortable talking about the calculation.
20·· ·of MSS-2.                                                   20·· · · ·Q· ··Okay.··You're comfortable talking about how we
21·· · · ·Q· ··And exactly what is the amount of those costs      21·· ·get to 10.6 million?
22·· ·in the test year?                                           22·· · · ·A· ··Generally speaking, I can generally talk about
23·· · · ·A· ··I believe the test year costs are $1.7 million.    23·· ·it, yes.··But it came from Mr. Considine's thing, but I
24·· · · ·Q· ··And you also support the MSS-2 costs in the        24·· ·can talk about it.
25·· ·reconciliation period, or the other MSS costs?··I'm         25·· · · ·Q· ··Okay.··Fair enough.··Now, if we turn to your


                            KENNEDY REPORTING SERVICE, INC.
                                                    512.474.2233
                                                                                        Page 4 (Pages 731-734)
                                                     Page 731                                                                     Page 733

·1··  · · ·Q· ··Under the system agreement, the operating         ·1·· · · · · · · · ·admitted)
·2··  ·companies that we've talked about are to equalize their    ·2·· · · ·Q· ··(BY MR. LAWTON)··What I want to focus on,
 ·3·· ·cost of transmission.··Is that correct?                    ·3·· ·Mr. Cicio, is last page of Cities 28.··Are you there,
 ·4·· · · ·A· ··Of certain transmission.··It's not all            ·4·· ·sir?··It's a table.··Do you see that table?
 ·5·· ·transmission.··There are certain guidelines within the     ·5·· · · ·A· ··Yes, I see the table.
 ·6·· ·service schedule that govern what transmissions are        ·6·· · · ·Q· ··This is the response to Cities 3-3 g.··Correct?
 ·7·· ·equalized.                                                 ·7·· · · ·A· ··That's correct.
 ·8·· · · ·Q· ··And generally speaking, would you agree that      ·8·· · · ·Q· ··Now, what we have here on this table on the
 ·9·· ·it's all transmission assets at 230 kV and above?          ·9·· ·left-hand side is the year from 2006 to 2011, along with
10·· · · ·A· ··I think that's generally the case.                 10·· ·a grand total.··Do you see that?
11·· · · ·Q· ··Okay.··So if a utility has a lot of                11·· · · ·A· ··Yes, I see that.
12·· ·transmission relative to the other operating companies      12·· · · ·Q· ··And then across the top of the table, we have
13·· ·and its responsibility ratio reflects it, it may get        13·· ·EAI.··That would be the Arkansas company --
14·· ·paid MSS-2 dollars -- correct -- from the other             14·· · · ·A· ··That's correct.
15·· ·operating companies?                                        15·· · · ·Q· ··-- and EGSI.··Which company is that, the
16·· · · ·A· ··I'm not sure I would characterize it exactly       16·· ·Louisiana Texas -- I mean, Louisiana Gulf States?
17·· ·that way.                                                   17·· · · ·A· ··That is both companies, ETI and EGSL.··That was
18·· · · ·Q· ··Okay.··Well, would you agree with this             18·· ·prior to the jurisdictional separation of those two
19·· ·statement:··Some of the operating companies are paid on     19·· ·companies.
20·· ·a monthly basis for transmission and others pay the         20·· · · ·Q· ··Fair enough.··And then you have -- and so what
21·· ·cost?                                                       21·· ·happened is on January 1st, 2008, Texas and Louisiana
22·· · · ·A· ··And there are long companies and there are         22·· ·separated.··Correct?
23·· ·short companies, as it relates to equalizable               23·· · · ·A· ··I think that's the case.
24·· ·transmission investment.                                    24·· · · ·Q· ··Okay.··And then the next company is ELL.··Which
25·· · · ·Q· ··Okay.··I've put some -- had Ms. Mayhall put        25·· ·one is that?··That's another operating company?

                                                     Page 732                                                                     Page 734

·1··  ·some exhibits in front of you, and the first one I want    ·1·· · · ·A· ··That's Entergy Louisiana.
·2··  ·to look at is what has been marked as Cities Exhibit 28.   ·2·· · · ·Q· ··And EGSL, that's the Louisiana version that
 ·3·· · · ·A· ··I have it.··Yes, I have it.··Okay.··Cities        ·3·· ·separated.··Correct?
 ·4·· ·Exhibit 28 is the response to Cities 3-3?                  ·4·· · · ·A· ··Right.··That's the Louisiana portion of what
 ·5·· · · ·Q· ··Yes.··You're getting ahead of me, sir.            ·5·· ·used to be EGSI.
 ·6·· · · ·A· ··Okay.                                             ·6·· · · ·Q· ··And EMI would be the Mississippi company I
 ·7·· · · ·Q· ··Would you agree that Cities Exhibit 28 is a       ·7·· ·forgot before.··Right?
 ·8·· ·discovery response to Cities 3-3?                          ·8·· · · ·A· ··Entergy Mississippi, correct.
 ·9·· · · ·A· ··Yes, I would agree with that.                     ·9·· · · ·Q· ··And ENOI, that would be the New Orleans
10·· · · ·Q· ··And would you agree with me that you are the       10·· ·operations?
11·· ·sponsoring witness for Subparts g. and h.?                  11·· · · ·A· ··That would be Entergy New Orleans, Inc.
12·· · · ·A· ··I am the sponsoring witness for g. and h.          12·· · · ·Q· ··And ETI at the far right would be the company
13·· · · ·Q· ··And you've seen this document before, haven't      13·· ·we're here about today, Entergy Texas, Inc.··Correct?
14·· ·you, sir?                                                   14·· · · ·A· ··That's correct.
15·· · · ·A· ··I have seen it.                                    15·· · · ·Q· ··And let's look at ETI for a second starting in
16·· · · ·Q· ··Okay.··And it's true and correct to the best of    16·· ·2008.··You have a number that says a negative
17·· ·your knowledge.··Correct?                                   17·· ·$2,660,494.··Do you see that?
18·· · · ·A· ··That's correct.                                    18·· · · ·A· ··Yes, I do.
19·· · · · · · · · ·MR. LAWTON:··Your Honor, I would offer, at    19·· · · ·Q· ··And what does that number mean?
20·· ·this time, Cities 28.                                       20·· · · ·A· ··That means for the year -- calendar year
21·· · · · · · · · ·JUDGE WALSTON:··Any objection?                21·· ·2008 that Entergy Texas received MSS-2 payments in the
22·· · · · · · · · ·MR. WESTERBURG:··No, Your Honor.              22·· ·amount of $2.6 million.
23·· · · · · · · · ·JUDGE WALSTON:··Cities Exhibit 28 is          23·· · · ·Q· ··So the other operating companies had to pay
24·· ·admitted.                                                   24·· ·Entergy Texas transmission dollars for equalization in
25·· · · · · · · · ·(Exhibit Cities··No. 28 marked and            25·· ·2008.··Correct?


                            KENNEDY REPORTING SERVICE, INC.
                                                    512.474.2233
                                                                                         Page 5 (Pages 735-738)
                                                     Page 735                                                                      Page 737

·1··  · · ·A· ··On a net basis -- net for the year.               ·1·· · · ·Q· ··Okay.··Well, I just want to make sure what it
·2··  · · ·Q· ··On a net basis?                                   ·2·· ·is because we said the test year was 1.7.··I'm trying to
 ·3·· · · ·A· ··Month-to-month it could have been different.      ·3·· ·distinguish it.
 ·4·· · · ·Q· ··Okay.··Well, if we look -- let's stay on          ·4·· · · ·A· ··Okay.
 ·5·· ·2008 for a moment.··Okay?                                  ·5·· · · ·Q· ··Now, if we go to the bottom of that graph,
 ·6·· · · · · · · · ·If we look across all the 2008 numbers and   ·6·· ·below it, you -- it looks like what appears to be the
 ·7·· ·if we were to add, for example, the EAI number for 2008,   ·7·· ·test year numbers.··Is that correct, sir?
 ·8·· ·that's a negative 1.4 million.··Do you see that?           ·8·· · · ·A· ··That's what it looks like, yes.
 ·9·· · · ·A· ··Yes.                                              ·9·· · · ·Q· ··It says -- its starts off July 2010-June 6th --
10·· · · ·Q· ··And that means they got paid.··Correct?            10·· ·June 2011.··Correct?
11·· · · ·A· ··Again; for the year, yes.                          11·· · · ·A· ··That's right.
12·· · · ·Q· ··Right.··And then we see the ELL number is          12·· · · ·Q· ··Okay.··And so these are the actual numbers in
13·· ·something like 7.8 million for 2008.··Do you see that?      13·· ·the test year.··Right?
14·· · · ·A· ··Yes, I do.                                         14·· · · ·A· ··These are the actual amounts recorded for MSS-2
15·· · · ·Q· ··And they were paid 7.8 million.··Right?            15·· ·during the test year.
16·· · · ·A· ··Yes.                                               16·· · · ·Q· ··And Entergy Texas ended up paying the other
17·· · · ·Q· ··And EGSL had to pay.··It's a positive number.      17·· ·operating companies roughly 1.7 million.··Correct?
18·· ·That means they had to pay some money.··Correct?            18·· · · ·A· ··Yes.··They paid 1.7 million on a net basis for
19·· · · ·A· ··That's right.                                      19·· ·the year.
20·· · · ·Q· ··If we added the numbers across in any year,        20·· · · ·Q· ··On a net basis.··And if we added the test year
21·· ·would they equal zero?                                      21·· ·numbers across, it would, again, equal zero on a system
22·· · · ·A· ··They should equal zero.                            22·· ·basis.··Right?
23·· · · ·Q· ··And the reason they equal zero is basically the    23·· · · ·A· ··That's correct.
24·· ·short companies have to pay the long companies.             24·· · · ·Q· ··Fair enough.··And it's that 1.7 million --
25·· ·Correct?                                                    25·· ·1,753,797 that you sponsor?

                                                     Page 736                                                                      Page 738

·1··  · · ·A· ··It's a system, so we're equalizing the cost       ·1··  · · ·A· ··Yes, that's what I sponsor in my testimony.
·2··  ·among the system.··So for the system, it would equal --    ·2··  · · ·Q· ··Fair enough.··But to be clear -- just go back
 ·3·· ·should equal zero.                                          ·3·· ·there a second -- what you're asking for in this case --
 ·4·· · · ·Q· ··Fair enough.··Now, in -- if we look at ETI, we     ·4·· ·I'm sorry.
 ·5·· ·see in 2000 -- I think it's 2010, we have a positive        ·5·· · · · · · · · ·What the company is asking for in this
 ·6·· ·number of 559,000.··Do you see that?                        ·6·· ·case is roughly not the 1.7 million test year number.
 ·7·· · · ·A· ··Yes, I do.                                         ·7·· ·They're asking for a number of 10.6 million.··Correct?
 ·8·· · · ·Q· ··That means on the year, Entergy Texas, Inc.,       ·8·· · · ·A· ··They're asking for 10.6 million because, you
 ·9·· ·had to pay money to the operating companies -- other        ·9·· ·know, the way the calculation works, if there's added
10·· ·operating companies.··Correct?                              10·· ·investment across the companies, which you see here --
11·· · · ·A· ··That's correct.                                    11·· ·there are changes in transmission investment year to
12·· · · ·Q· ··Okay.··And then in the following year, 2011,       12·· ·year, and so as those transmission projects are put in
13·· ·they had to pay -- "they" being ETI, Entergy Texas --       13·· ·service, the balance will shift between the different
14·· ·had to pay roughly 1.3 million.··Correct?                   14·· ·companies, depending on their transmission
15·· · · ·A· ··That's correct.                                    15·· ·responsibility relative to their investment.
16·· · · ·Q· ··But on a grand total basis, you just added         16·· · · ·Q· ··Fair enough.··Now, sir, I've had -- I want to
17·· ·those numbers up and said, on a net basis, Entergy          17·· ·go through that calculation for a moment so we all
18·· ·Texas, Inc., got paid 1.7 million.··Correct?                18·· ·understand how it's done.
19·· · · ·A· ··I think if you added up Entergy -- add all the     19·· · · · · · · · ·I've had a two-page demonstrative put in
20·· ·years for Entergy Texas, they would have received           20·· ·front of you, and the first page is just a. through w.
21·· ·1.7 million.                                                21·· ·You'll see those lines.··And the second page is a sheet
22·· · · ·Q· ··Fair enough.                                       22·· ·that has a bunch of numbers.··Okay, sir?··Do you see
23·· · · ·A· ··We're just saying for four years, you know,        23·· ·that?
24·· ·they got a net payment.··It's not -- that's just a          24·· · · ·A· ··I have this in front of me, yes.
25·· ·total.                                                      25·· · · ·Q· ··And I just wanted you to assist us on how this


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·1·· · · ·Q· ··Okay.··Fair enough.··Fair enough.                           ·1··  · · · · · · · ·MR. LAWTON:··Thank you.
·2·· · · · · · · · ·Now, you said, when we started this                    ·2··  · · ·Q· ··(BY MR. LAWTON)··What's the rate year, sir, in
·3·· ·examination this morning, that you could talk about the               ·3·· ·this case?··Do you know?
·4·· ·$10.6 million request.                                                ·4·· · · ·A· ··I believe it begins June of '12 and ends May of
·5·· · · · · · · · ·JUDGE WALSTON:··Can I ask one clarifying                ·5·· ·'13.
·6·· ·question just to make sure I'm clear?                                 ·6·· · · ·Q· ··So June 2012 to May 2013.··That's your rate
·7·· · · · · · · · ·MR. LAWTON:··Yes, sir.                                  ·7·· ·year, and you would agree that's a forecast period.
·8·· · · · · · · · ·JUDGE WALSTON:··You said some were removed              ·8·· ·Correct?
·9·· ·due to an adjustment.··Is that -- do I understand some                ·9·· · · ·A· ··I believe that's -- I'm not exactly sure that
10·· ·assets were included that should not have been included              10·· ·those are the 12 months, but I believe it's generally --
11·· ·and then removed, or why were they removed?··I didn't                11·· · · ·Q· ··I think you got it right.
12·· ·follow that.                                                         12·· · · ·A· ··Okay.
13·· · · · · · · · ·THE WITNESS:··Each month we -- being my                13·· · · ·Q· ··I think it's right.
14·· ·group -- receives the equalizable transmission                       14·· · · ·A· ··Okay.
15·· ·investment from the transmission organization, who, I'm              15·· · · ·Q· ··So your 10.6 dollar-million estimate in this
16·· ·assuming, get it from the property accounting records.               16·· ·case is based upon MSS-2 costs for this time period,
17·· · · · · · · · ·So they look at the investment in                      17·· ·June 2012 to May 2013.··Correct, sir?
18·· ·transmission month to month, and, say, based on the                  18·· · · ·A· ··It's based on the expected investment, the
19·· ·rules of MSS-2, what should be determined to be                      19·· ·changes in responsibility ratio for that 12-month
20·· ·equalizable investment.                                              20·· ·period.
21·· · · · · · · · ·They review that as they provide it, and               21·· · · ·Q· ··Okay.··And do you have Cities Exhibit 39 there,
22·· ·in that particular month, there was an adjustment where              22·· ·sir?··That's the demonstrative with all the numbers.
23·· ·they said that the investment that was there the month               23·· · · ·A· ··Yes, I have that in front of me.
24·· ·before -- a portion of that was no longer equalizable                24·· · · ·Q· ··Okay.··For that time period that we just
25·· ·and shouldn't have been equalizable.··So it was adjusted             25·· ·discussed, June 2012 to May 2013, you had to get an

                                                                Page 760                                                                Page 762

·1·· ·out.··The investment is still there.··It's just not                  ·1·· ·estimate of all the plant costs on Lines a. through d.
·2·· ·determined to be equalizable investment.                             ·2·· ·Correct?
·3·· · · · · · · · ·JUDGE BURKHALTER:··Meaning it's not 230 kV             ·3·· · · ·A· ··That's correct.··We would had to have a point
·4·· ·or above?                                                            ·4·· ·of view on the expected transmission investment.
·5·· · · · · · · · ·THE WITNESS:··Generally, yes, that's                   ·5·· · · ·Q· ··Somebody had to forecast all that stuff.
·6·· ·correct.                                                             ·6·· ·Right?
·7·· · · ·Q· ··(BY MR. LAWTON)··Now, sir --                                ·7·· · · ·A· ··They had to forecast, or they looked at what
·8·· · · · · · · · ·MR. LAWTON:··I'm sorry.··I don't want to               ·8·· ·projects were already being built that they thought were
·9·· ·interrupt again.                                                     ·9·· ·going to be completed, so a forecast based on existing
10·· · · · · · · · ·JUDGE WALSTON:··Okay.                                  10·· ·projects and forecasted projects.
11·· · · ·Q· ··(BY MR. LAWTON)··Now, the company has, in fact,             11·· · · ·Q· ··Okay.··And then if we look under the category
12·· ·forecast a 10.6 million-dollar number for this MSS-2                 12·· ·cost of capital; debt ratio, bond costs, all the way
13·· ·category.··Correct?                                                  13·· ·down to Item e., did you get a forecast for all those
14·· · · ·A· ··It's 10.696, I think.                                       14·· ·numbers?
15·· · · ·Q· ··You've got more decimal places than I, sir.                 15·· · · ·A· ··I don't think those numbers were updated for
16·· · · · · · · · ·But this $10.6 million is roughly a                    16·· ·that period.
17·· ·9 million-dollar increase, and it's included in the                  17·· · · ·Q· ··They weren't?
18·· ·111 million request the company originally made.··Right?             18·· · · ·A· ··I don't -- I don't know, to be honest.
19·· · · ·A· ··It's a -- yes.··The $10.69 million is the rate              19·· · · ·Q· ··You don't know?
20·· ·year -- expected rate year MSS-2 expense.                            20·· · · ·A· ··No, I don't.
21·· · · ·Q· ··All right.··Fair enough.··Now, go back, for a               21·· · · ·Q· ··Who knows?
22·· ·moment, to the demonstrative for Cities, Exhibit 39.                 22·· · · ·A· ··Somebody that -- the gentlemen or gentleman
23·· · · · · · · · ·MR. LAWTON:··Your Honor, may I use this a              23·· ·that reviewed that.··I don't -- I don't know personally.
24·· ·second?                                                              24·· · · ·Q· ··But I thought you reviewed it.
25·· · · · · · · · ·JUDGE WALSTON:··Yes.                                   25·· · · ·A· ··I reviewed it, but I don't remember whether


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·1··  ·those changed or not.··I just don't remember that.        ·1··  · · ·Q· ··When they did the load forecast for Entergy
·2··  · · ·Q· ··Let's go to the tax rate.··Do you think that     ·2··  ·Texas, did they have an increase in load for Entergy
 ·3·· ·changed?                                                   ·3·· ·Texas, sir?··Do you know?
 ·4·· · · ·A· ··I don't -- the factors I'm not sure of.           ·4·· · · ·A· ··I don't know.
 ·5·· · · ·Q· ··Okay.··Well, would that include the factors       ·5·· · · ·Q· ··Is the -- okay.
 ·6·· ·under O&M expenses, too?                                   ·6·· · · · · · · · ·The last area that I want to ask you about
 ·7·· · · ·A· ··Everything from cost of capital through, you      ·7·· ·is I think on your -- I have passed out this morning --
 ·8·· ·know, the net investment ratio.··Those numbers, I just     ·8·· ·is copy of Cities Exhibit 7.··It's part of 10-K.··It's
 ·9·· ·don't know if the financial factors were updated.          ·9·· ·already into the record.··I just wanted to ask you a
10·· · · ·Q· ··Is there somebody in this case I can ask about    10·· ·little bit about the 10-K.
11·· ·it?                                                        11·· · · ·A· ··Okay.
12·· · · ·A· ··I don't know, Mr. Lawton.                         12·· · · ·Q· ··Go to Page 364 of the 10-K, sir.
13·· · · ·Q· ··Okay.··What about all the other numbers, net      13·· · · ·A· ··Okay.··I'm there.
14·· ·investment ratio, and all that, was that --                14·· · · ·Q· ··Under "Other income statement variances" -- do
15·· · · ·A· ··Those are calculations, so those are embedded     15·· ·you see that in bold?
16·· ·in -- if you update, you know, the net transmission        16·· · · ·A· ··Yes, I see that.
17·· ·investment, then you update, you know, the ratio -- that   17·· · · ·Q· ··Go to the first bullet point and read that to
18·· ·ratio anyway.                                              18·· ·yourself.
19·· · · ·Q· ··Would you agree with me, sir -- we went through   19·· · · ·A· ··To myself?
20·· ·this -- that the cost of capital and all these O&M         20·· · · ·Q· ··Yes.
21·· ·factors are important parts of the calculation as well?    21·· · · · · · · · ·(Brief pause)
22·· · · ·A· ··Yes.··They're important parts of the              22·· · · ·A· ··Okay.··I've read it.
23·· ·calculation, but they don't typically vary a great deal.   23·· · · ·Q· ··(BY MR. LAWTON)··All right.··What I understand
24·· ·I mean, the significant change that generated the          24·· ·the 10-K -- the company, Entergy Corp., is reporting
25·· ·10.6 million was the change in the investment.             25·· ·that Entergy Texas, Inc., had some billing adjustments

                                                    Page 764                                                                 Page 766

·1··  · · ·Q· ··Well, let's talk about the load responsibility   ·1·· ·to make in its MSS-2 expenditures.··Is that a fair
·2··  ·ratio.··Isn't that line -- what line is that, sir?        ·2·· ·characterization creation of that statement?
 ·3·· · · ·A· ··On the demonstrative exhibit, it's Line s.       ·3·· · · ·A· ··As it reads here, there was a transmission -- a
 ·4·· · · ·Q· ··Line s.··And isn't that load responsibility      ·4·· ·change of 2011 -- down to year 2011 over calendar year
 ·5·· ·ratio based upon the forecast of loads in your example    ·5·· ·2010.··There was a variance in transmission expenses of
 ·6·· ·here in your estimate?                                    ·6·· ·roughly 8 and a half million dollars.
 ·7·· · · ·A· ··Are we talking about the rate year?              ·7·· · · ·Q· ··Okay.··Would those be -- that 8 and a half
 ·8·· · · ·Q· ··Yes, sir.··Did somebody forecast the load        ·8·· ·million referred to MSS-2 payments?
 ·9·· ·responsibility for the rate year to get 10.6 million?     ·9·· · · ·A· ··The 8 and a half million appears to be due to a
10·· · · ·A· ··Yes, they updated -- that they did update, but    10·· ·change in the MSS-2 expenses from 2011 to 2010, a
11·· ·it's a very small percentage.··I mean, basically out of    11·· ·portion of that, and it's not a large portion of that,
12·· ·10.6, you know, that was less than 15 percent of the       12·· ·was related to that 16-year period from 1996 to 2011,
13·· ·adjustment.                                                13·· ·the billing adjustment for that period.
14·· · · ·Q· ··Based on your calculations.··Correct?             14·· · · ·Q· ··Okay.··So would it fair to say that the
15·· · · ·A· ··Based on my calculations.··Correct.               15·· ·company, Entergy Texas, Inc., or one of the groups
16·· · · ·Q· ··In rebuttal testimony, and we're going to talk    16·· ·there, did an audit for that time period, 1996 to 2011?
17·· ·about it at another time.··Right?                          17·· ·Fair?
18·· · · ·A· ··It was calculated, you know, under my             18·· · · ·A· ··There was a review of the MSS-2 balances for
19·· ·supervision, and it's included in my rebuttal testimony.   19·· ·that period, 1996 to 2011, that resulted in a change in
20·· · · ·Q· ··Okay.                                             20·· ·the MSS-2 payments for -- over that 16-year period, and
21·· · · ·A· ··It's a very small percentage of the total.        21·· ·when you look at 2011 versus 2010, the variance is 8 and
22·· · · ·Q· ··Who did the load forecast, sir?                   22·· ·a half million dollars for that period, but only a
23·· · · ·A· ··I believe the load forecast was generated out     23·· ·small -- less than half of that really related to that
24·· ·of one of the groups in our system planning                24·· ·adjustment.
25·· ·organization.                                              25·· · · · · · · · ·It could be other changes in transmission


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·1··  ·know whether he's also appeared for cross-examination in   ·1··  ·Attachment 5 of the inter-system bill.
·2··  ·this proceeding?                                           ·2··  · · ·Q· ··And has the company provided the inter-system
 ·3·· · · ·A· ··Yes, he's already appeared.                        ·3·· ·bill for a period of time in this case?
 ·4·· · · ·Q· ··And, now, what does -- does Mr. Considine          ·4·· · · ·A· ··I believe in Cities 5-1, it's provided these
 ·5·· ·support the pro forma for MSS-2?                            ·5·· ·attachments, I believe, through February of 2011 --
 ·6·· · · ·A· ··Mr. Considine also supports the pro forma for      ·6·· ·2012.··I'm sorry.
 ·7·· ·MSS-2.                                                      ·7·· · · ·Q· ··And that is an attachment to 5-1?
 ·8·· · · ·Q· ··And what is the nature of his support for that?    ·8·· · · ·A· ··Yes.
 ·9·· · · ·A· ··Mr. Considine looks -- took all the changes to     ·9·· · · ·Q· ··And I think that is Cities Exhibit 29, so let's
10·· ·the test year that were perceived to be known and           10·· ·turn to that.
11·· ·measurable changes to the test year and adjusted the        11·· · · ·A· ··Okay.
12·· ·test year expenses by those known and measurable            12·· · · ·Q· ··Now, would we find Page 2 of Cities Exhibit 39
13·· ·adjustments.                                                13·· ·in the documents attached to -- or in the attachments to
14·· · · ·Q· ··Do you know whether Mr. Considine has already      14·· ·Cities Exhibit 29?
15·· ·appeared for cross-examination in this proceeding?          15·· · · ·A· ··Attachment 5 is -- which is the second page of
16·· · · ·A· ··Yes, he has already appeared.                      16·· ·the Cities exhibit, is found as an attachment to Cities
17·· · · ·Q· ··I would like to turn to Mr. Lawton's               17·· ·5-1.
18·· ·demonstrable exhibit.                                       18·· · · ·Q· ··Right.··And, I mean, this -- what I'm talking
19·· · · · · · · · ·MR. WESTERBURG:··Was that Exhibit 37?         19·· ·about is the very specific month that -- could we turn
20·· · · · · · · · ·JUDGE WALSTON:··39.                           20·· ·to that?
21·· · · · · · · · ·MR. WESTERBURG:··39.··Excuse me.              21·· · · · · · · · ·JUDGE WALSTON:··Which page are we turning
22·· ·Exhibit 39.                                                 22·· ·to?
23·· · · ·Q· ··(BY MR. WESTERBURG)··Mr. Lawton took you           23·· · · · · · · · ·MR. WESTERBURG:··What I'm trying to do,
24·· ·through a discussion of the numbers and the columns and     24·· ·Your Honor, is find, in Cities Exhibit 29, 5-1, which is
25·· ·the lines that appear on Page 2 here.··You recall that?     25·· ·a number of Attachment 5 to the inter-system bill.··I'm

                                                     Page 780                                                          Page 782

·1··  · · ·A· ··Yes, I do.                                        ·1··  ·trying to find this specific page that is Page 2 of
·2··  · · ·Q· ··Do you have a sense, or do you have an opinion,   ·2··  ·Cities 39.··So I'm dealing with both 39 and 29.
 ·3·· ·Mr. Cicio, about -- with respect to the number in the       ·3·· · · ·A· ··If you go to Page 22 of Cities 5-1, you'll find
 ·4·· ·bottom right-hand corner, which on Exhibit 39, it shows     ·4·· ·the July 2011 MSS-2 calculation, which is the same page
 ·5·· ·an MSS-2 payment for ETI -- with respect to that number,    ·5·· ·as -- second page of the Cities demonstrative exhibit.
 ·6·· ·do you know, or would you have an opinion as to which       ·6·· · · ·Q· ··(BY MR. WESTERBURG)··Okay.··Thank you,
 ·7·· ·numbers or groups of numbers change more than others to     ·7·· ·Mr. Cicio.··And can you verify whether all of the
 ·8·· ·affect that number?                                         ·8·· ·attachments to Cities 5-1, the -- sounds strange, but
 ·9·· · · ·A· ··I mean, the majority of this calculation is --     ·9·· ·I'm referring to them as the Attachment 5s -- with an
10·· ·a large percent of the calculation turns on the change      10·· ·"S" on the end of it.
11·· ·in total investment and net transmission investment.        11·· · · ·A· ··Okay.
12·· ·Generally speaking, the rest of the components, the cost    12·· · · ·Q· ··All of those are historical.··Is that correct?
13·· ·rates, the responsibility ratios don't change typically,    13·· · · ·A· ··Yes, these are historical periods.··I think the
14·· ·you know, much year over year.                              14·· ·last month is February of 2012.
15·· · · ·Q· ··And, now, this document we're looking at, at       15·· · · ·Q· ··And does that mean that the information
16·· ·Page 2 of exhibit -- Cities Exhibit 39, this same form      16·· ·contained on these Attachment 5s reflect actual data and
17·· ·of document -- well, let me ask you, is -- this is a        17·· ·recordings return?
18·· ·page in an attachment to what's referred to as the          18·· · · ·A· ··These are based on the actual inter-system
19·· ·inter-system bill.··Is that correct?                        19·· ·bills for those representative months.
20·· · · ·A· ··Yes, that's correct.                               20·· · · ·Q· ··Okay.··And can we turn to the very last page of
21·· · · ·Q· ··And just for the sake of the way the transcript    21·· ·Attachment 5, which would be Page 29?
22·· ·might read, what page is this to the inter-system bill      22·· · · ·A· ··Yes, I'm there.
23·· ·in terms of -- you know, what part of the inter-system      23·· · · ·Q· ··And what is this?
24·· ·bill would this be a page of?                               24·· · · ·A· ··This is the Attachment 5 for February of 2012.
25·· · · ·A· ··This is -- the MSS-2 calculation is found on       25·· · · ·Q· ··Just -- do you know why -- we're sitting here


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·1·· ·today in April.··Do you know why we don't have March               ·1·· · · ·Q· ··Now, there was also discussion with Mr. Lawton
·2·· ·attached to attachment -- Cities Exhibit 29?                       ·2·· ·about an adjustment to MSS-2.··Do you recall that?
·3·· · · ·A· ··Yes.··The inter-system bill is prepared twice a           ·3·· · · ·A· ··Yes, I do.
·4·· ·month.··It's prepared on the second work day of a month,           ·4·· · · ·Q· ··Now, does -- the adjustment that's been
·5·· ·and the actual bill is rendered about 30 days after the            ·5·· ·discussed, does that play a part in the increase in the
·6·· ·conclusion of the preceding month.··So the actual March            ·6·· ·MSS-2 expense from the test year to what we see here on
·7·· ·bill was actually prepared this week -- was issued this            ·7·· ·Page 29 of Exhibit 29?
·8·· ·week.··And so it's not yet -- it will be provided once             ·8·· · · ·A· ··By -- what you're saying is, "does it play a
·9·· ·it was complete, which is, I think, mid-week or early              ·9·· ·part."··To the extent there were changes in the
10·· ·part of this week.                                                 10·· ·investment balance resulting from that review from '96
11·· · · ·Q· ··Okay.··So February was the latest available?              11·· ·to 2011, this calculation is based on cumulative
12·· · · ·A· ··Yes, February was the latest available.                   12·· ·balances of transmission investment.
13·· · · ·Q· ··Okay.··And what's the number in the lower                 13·· · · · · · · · ·So to the extent there was any change, it
14·· ·right-hand corner under payments for ETI for February,             14·· ·would have had some effect on those balances, but the
15·· ·which is Page 29?                                                  15·· ·majority of this has been -- has occurred post that
16·· · · ·A· ··For February of 2012, ETI had an MSS-2 payment            16·· ·adjustment -- the change in transmission investment, the
17·· ·of $698,289.82.                                                    17·· ·majority of which has been just new investment that's
18·· · · ·Q· ··And those are based on -- that is based on                18·· ·been put in service.
19·· ·actual investment and transmission of the operating                19·· · · ·Q· ··Maybe this is a cleaner question.··Does the
20·· ·companies.··Is that right?                                         20·· ·February Attachment 5 on Page 29 reflect the adjustment
21·· · · ·A· ··That's correct.                                           21·· ·and equalizable investment that you discussed with
22·· · · ·Q· ··There's no projections on this page?                      22·· ·Mr. Lawton?
23·· · · ·A· ··There are no projections on this page.                    23·· · · ·A· ··Does it reflect the equalizable --
24·· · · ·Q· ··Do you know, Mr. Cicio, what -- or if you have            24·· · · ·Q· ··The adjustment in equalizable investment you
25·· ·it, I think it's a simple calculation.                             25·· ·discussed with Mr. Lawton.

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·1··  · · · · · · · ·Do you know what, you know, 12 times                ·1··  · · ·A· ··It reflects the balance -- the changes in the
·2··  ·698,000 would be?                                                 ·2··  ·balances.
 ·3·· · · ·A· ··No, I don't have a calculator on me, but if I             ·3·· · · ·Q· ··Well, let me ask for clarification.··What was
 ·4·· ·rounded it to 700,000, it would be about $8.4 million.             ·4·· ·the adjustment?··What was adjusted?
 ·5·· · · ·Q· ··8.4.··And what was the amount of test year                ·5·· · · ·A· ··What was adjusted during that -- from '96 to
 ·6·· ·MSS-2 expenses?                                                    ·6·· ·2011, there were changes in the investment balances
 ·7·· · · ·A· ··The test year amount was 1.7 million.                     ·7·· ·across the different companies.
 ·8·· · · ·Q· ··Do you know whether the MSS-2 payments, as                ·8·· · · ·Q· ··The equalizable investment?
 ·9·· ·reflected in this Cities 29 since the test year, have              ·9·· · · ·A· ··The equalizable investment.
10·· ·been increasing or decreasing?                                     10·· · · ·Q· ··Okay.··Are those changes reflected in Page 29
11·· · · ·A· ··To get to -- I mean, if I looked at the test              11·· ·of Exhibit 29?
12·· ·year payments and receipts -- and since the test year,             12·· · · ·A· ··Yes.··Yes, they are reflected.
13·· ·they've been all payments, and they've been increasing             13·· · · ·Q· ··Do you know whether those changes will continue
14·· ·since the end of the test year.                                    14·· ·to be reflected going forward in the MSS-2 payments?
15·· · · · · · · · ·I mean, I'm going back, you know, since              15·· · · ·A· ··It's a cumulative balance, so to the extent
16·· ·the test year.··I think there was a slight dip in the --           16·· ·those changes in -- those assets are still part of the
17·· ·in the month of January, it went from 620 to 596, but              17·· ·net investment, yes, they will continue to be included.
18·· ·generally above the test year monthly levels.                      18·· · · ·Q· ··Mr. Lawton asked you about certain operating
19·· · · ·Q· ··And do you know why that has occurred?                    19·· ·companies leaving the system agreement or having given
20·· · · ·A· ··There's been, as we talked about, you know, a             20·· ·notice to leave the system agreement.··Do you recall
21·· ·major factor in the change in how the payments and                 21·· ·that?
22·· ·receipts for MSS-2 are generated by transmission                   22·· · · ·A· ··Yes, I do.
23·· ·investment across the system.··And so there's been a               23·· · · ·Q· ··And those operating companies are Entergy
24·· ·fair amount of transmission investment built and placed            24·· ·Mississippi and Entergy Arkansas?
25·· ·in service across the system during this period.                   25·· · · ·A· ··That's correct.


                                   KENNEDY REPORTING SERVICE, INC.
                                                            512.474.2233
                                                                                               Page 19 (Pages 791-794)
                                                                 Page 791                                                                  Page 793

·1··  ·Do you see that?                                                     ·1·· ·projects that are in service or in service early or
·2··  · · ·A· ··Yes.··I think it's Line s. on the --                        ·2·· ·projected to be in service, and there's a construction
 ·3·· · · ·Q· ··And that's what you just explained.··Correct?               ·3·· ·amount associated with each of those projects.··So
 ·4·· · · ·A· ··I explained coincident peak.··Responsibility                ·4·· ·they're measurable by that aspect of it.
 ·5·· ·ratio is the average of the 12 -- preceding 12 months.               ·5·· · · ·Q· ··What value does ETI receive for its MSS-2
 ·6·· · · ·Q· ··Twelve months what, coincident peak?                        ·6·· ·payments?
 ·7·· · · ·A· ··Twelve months coincident peak.                              ·7·· · · ·A· ··What ETI receives as a benefit from its MSS-2
 ·8·· · · ·Q· ··Okay.··Now, is there any other calculation on               ·8·· ·payments is the ability to have resources available to
 ·9·· ·this page that reflects the concept of load, other than              ·9·· ·them through the use of the system's bulk electric power
10·· ·responsibility ratio?                                                 10·· ·system.··So if there are resources that are in a
11·· · · ·A· ··No, there's not.                                             11·· ·different area outside of Texas, by use of that system,
12·· · · ·Q· ··Now, I think Mr. Lawton established that for                 12·· ·they have available to them purchased power
13·· ·the purpose of the projections into the rate year of                  13·· ·opportunities, other generation from the system that
14·· ·MSS-2, there needed to be a projection of the                         14·· ·would benefit customers in terms of lower fuel costs.
15·· ·responsibility ratio.··Is that correct?                               15·· · · · · · · · ·So it's part of the coordinated dispatch
16·· · · ·A· ··Yes, that's correct.                                         16·· ·of the system.··So if you have a coordinated dispatch,
17·· · · ·Q· ··Does that mean that the -- there was a                       17·· ·you have to rely on a system to move that power.··That
18·· ·projection of load in order to make that calculation?                 18·· ·would be the bulk electric power system.
19·· · · ·A· ··For purposes of the rate year calculation,                   19·· · · · · · · · ·MR. WESTERBURG:··I believe I'm finished.
20·· ·there was a forecasted load, which generated a forecast               20·· ·Can I have a 60-second break?
21·· ·of responsibility ratios that was included as part of                 21·· · · · · · · · ·JUDGE WALSTON:··Yeah.
22·· ·that.                                                                 22·· · · · · · · · ·(Brief pause)
23·· · · ·Q· ··Okay.··Have you made a calculation of what the               23·· · · · · · · · ·MR. WESTERBURG:··No more questions, Your
24·· ·rate year MSS-2 cost would be if you held the load and                24·· ·Honor.
25·· ·responsibility ratio constant from the test year?                     25·· · · · · · · · ·JUDGE WALSTON:··Do the Cities have

                                                                 Page 792                                                                  Page 794
·1·· · · ·A· ··Yes, I have.                                                 ·1··  ·recross?
·2·· · · ·Q· ··And what is that?                                            ·2··  · · · · · · · ·MR. LAWTON:··Just a bit, Your Honor.
·3·· · · ·A· ··That number was 86 percent of the total.··I                   ·3·· ·Thank you.
·4·· ·think the adjustment was around $9.4 million, I believe.               ·4·· · · · · · · · · · ··RECROSS-EXAMINATION
·5·· · · ·Q· ··That's what the adjustment would be in the rate               ·5·· ·BY MR. LAWTON:
·6·· ·year if you held it?                                                   ·6·· · · ·Q· ··Mr. Cicio, counsel asked you about your
·7·· · · ·A· ··Yes, the total.··I think the adjustment is                    ·7·· ·testimony I crossed you about regarding your support for
·8·· ·7-something.                                                           ·8·· ·the test year.··You support the test year number.
·9·· · · ·Q· ··Excuse me.··Thank you.··And you address that in               ·9·· ·Correct?
10·· ·your rebuttal?                                                        10·· · · ·A· ··That's correct.
11·· · · ·A· ··It's all -- yeah, the actual numbers are                     11·· · · ·Q· ··And he also asked you that -- whether you
12·· ·contained in my rebuttal testimony.                                   12·· ·supported the 9 million pro forma.··Correct?··And you
13·· · · ·Q· ··What is your opinion of whether the rate year                13·· ·do.··Right?
14·· ·change in transmission investment is known?                           14·· · · ·A· ··Yes, I support the calculation.
15·· · · ·A· ··I relied on Mr. McCulla's assessment of the                  15·· · · ·Q· ··Right.··And you've reviewed the calculations,
16·· ·known and measurable aspect of the MSS-2 -- MSS-2 inputs              16·· ·but you didn't do the calculations?
17·· ·of transmission investment that -- Mr. McCulla believes               17·· · · ·A· ··I have looked at the calculations, that's
18·· ·those are known and measurable changes, then they were                18·· ·correct.
19·· ·known and measurable changes and they were included in                19·· · · ·Q· ··Okay.··And you still don't know who did all the
20·· ·the pro forma adjustment.                                             20·· ·calculations for the load forecast.··Correct?
21·· · · ·Q· ··My next question for you I think you just                    21·· · · ·A· ··I don't know the specific individual.
22·· ·answered, but what is your opinion of whether the change              22·· · · ·Q· ··Okay.··And then you also said that
23·· ·in investment -- excuse me -- the change in the                       23·· ·Mr. Considine also supports the 9 million pro forma.
24·· ·investment dollars is measurable?                                     24·· ·Correct?
25·· · · ·A· ··They are measurable if they were based on                    25·· · · ·A· ··Yes, that's correct.


                                   KENNEDY REPORTING SERVICE, INC.
                                                               512.474.2233
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  · · · · · · · ··SOAH DOCKET NO. XXX-XX-XXXX
·1·                                                            ·1·
                                                                 · · · · · · · ·TABLE OF CONTENTS (CONTINUED)
 ···                                                           ·2·
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  · · · · · · · · · ·PUC DOCKET NO. 39896
·2·
 ···                                                           ·3·
                                                                 ·PRESENTATION ON BEHALF OF
  ·
·3·                                                             ··ENTERGY
                                                                   ·      TEXAS, INC. (CONTINUED)
 ···
  ·APPLICATION OF ENTERGY· ··)· ·STATE OFFICE OF
·4·                                                            ·4·
                                                                 ·
 ··TEXAS,
    ·     INC., FOR· · · · ··)
  ·AUTHORITY TO CHANGE RATES )
·5·                                                             ···· ··CHRIS E. BARRILLEAUX
 ··AND
    ·  RECONCILE FUEL COSTS, )                                 ·5·
                                                                 · · · · · ·- Direct (Olson)· · · · · · · · · · · · · ·149
  ·AND OBTAIN DEFERRED· · · ·)
·6·
 ··ACCOUNTING
    ·         TREATMENT· · ··) ADMINISTRATIVE HEARINGS          ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·151
  ·
·7·                                                            ·6·
                                                                 · · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··167
 ···
  ·
·8·                                                             ···· · · · ·- Redirect (Olson)· · · · · · · · · · · · ·187
 ···                                                           ·7·
                                                                 · · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·198
  ·
·9·
 ···                                                           ·8·
                                                                 · · ··SAMUEL C. HADAWAY
  ·
10·                                                             ···· · · · ·- Direct (Williams)· · · · · · · · · · · ··199
 ···
  · · · · · · · · · ·HEARING ON THE MERITS
11·                                                            ·9·
                                                                 · · · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·201
 ···
  · · · · · · · · ··Wednesday, May 2, 2012
12·                                                             ···· · · · ·- Cross (Griffiths)· · · · · · · · · · · ··212
 ···                                                           10·
                                                                 · · · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·230
  ·
13·
 ···                                                            ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··231
  ·
14·                                                            11·
                                                                 · · · · · ·- Recross (Griffiths)· · · · · · · · · · ··239
 ···
  · · · · · · · · · ··TABLE OF CONTENTS
15·                                                            12·
                                                                 ·PROCEEDINGS RECESSED· · · · · · · · · · · · · · · · ·246
 ···                                                           13·
                                                                 ·
  · · · ·(Volumes 1 through 7, Pages i through xlviii)
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                                                    Page ii                                                       Page iv
·1·
  · · · · · · · · · · ·TABLE OF CONTENTS                       ·1·
                                                                 · · · · · · · · ··TABLE OF CONTENTS
·2·
  · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE    ·2·
                                                                 · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE
·3·
  ·PROCEEDINGS, TUESDAY, APRIL 24, 2012 - VOL. 1· · · · ··5    ·3·
                                                                 ·PROCEEDINGS, WEDNESDAY, APRIL 25, 2012 - VOLUME 2· ··248
·4·
  ·OPENING STATEMENT ON BEHALF OF                              ·4·
                                                                 ·PRESENTATION ON BEHALF OF
 ··ENTERGY
    ·       TEXAS, INC. (Neinast)· · · · · · · · · · · · ·16    ··ENTERGY
                                                                   ·      TEXAS, INC. (CONTINUED)· · · · · · · · · · ··250
                                                               ·5·
                                                                 ·
·5·
  ·
                                                                ···· ··ROBERT D. SLOAN
 ··OPENING
    ·       STATEMENT ON BEHALF OF                             ·6·
                                                                 · · · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·250
·6·
  ·ENTERGY TEXAS, INC. (Wren)· · · · · · · · · · · · · ··22     ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·253
·7·
  ·OPENING STATEMENT ON BEHALF OF                              ·7·
                                                                 · · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·258
 ··CITIES
    ·      (Lawton)· · · · · · · · · · · · · · · · · · · ·37    ···· · · · ·- Redirect (Cyr)· · · · · · · · · · · · · ·285
·8·
  ·                                                            ·8·
                                                                 · · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·295
 ··OPENING
    ·       STATEMENT ON BEHALF OF                             ·9·
                                                                 · · ··H. VERNON PIERCE, JR.
·9·
  ·TEXAS INDUSTRIAL ENERGY CONSUMERS (VanMiddlesworth)· ·41     ···· · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·303
10·
  ·OPENING STATEMENT ON BEHALF OF                              10·
                                                                 · · · · · ·- Cross (Mack)· · · · · · · · · · · · · · ·305
 ··OFFICE
    ·      OF PUBLIC UTILITY COUNSEL (Ferris)· · · · · · ·49    ···· · · · ·- Cross (Younger)· · · · · · · · · · · · ··315
                                                               11·
                                                                 ·
11·
  ·
                                                                ···· ··MICHAEL P. CONSIDINE
 ··OPENING
    ·       STATEMENT ON BEHALF OF                             12·
                                                                 · · · · · ·- Direct (Neinast)· · · · · · · · · · · · ·317
12·
  ·STAFF (Smyth)· · · · · · · · · · · · · · · · · · · · ·52     ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·318
13·
  ·OPENING STATEMENT ON BEHALF OF                              13·
                                                                 · · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··352
 ··THE
    ·  UNITED STATES DEPARTMENT OF ENERGY (Porter)· · · ·54     ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·355
14·
  ·                                                            14·
                                                                 · · · · · ·- Redirect (Neinast)· · · · · · · · · · · ·358
15·
  ·PRESENTATION ON BEHALF OF                                    ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·362
 ··ENTERGY
    ·       TEXAS, INC.· · · · · · · · · · · · · · · · · ·60   15·
                                                                 ·
16·
  ·                                                             ··AFTERNOON
                                                                   ·        SESSION· · · · · · · · · · · · · · · · · ··365
 ···· ··JOSEPH DOMINO                                          16·
                                                                 ·
                                                                ··PRESENTATION
                                                                   ·           ON BEHALF OF
17·
  · · · · · ·- Direct (Wren)· · · · · · · · · · · · · · ·60    17·
                                                                 ·ENTERGY TEXAS, INC. (CONTINUED)· · · · · · · · · · ··366
 ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ··62    18·
                                                                 · · ··WALTER C. FERGUSON
18·
  ·                                                             ···· · · · ·- Direct (McNally)· · · · · · · · · · · · ·366
 ··AFTERNOON
    ·         SESSION· · · · · · · · · · · · · · · · · ··103   19·
                                                                 · · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·367
19·
  ·                                                             ···· · · · ·- Redirect (McNally)· · · · · · · · · · · ·369
 ··PRESENTATION
    ·            ON BEHALF OF                                  20·
                                                                 · · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·372
20·
  ·ENTERGY TEXAS, INC. (CONTINUED)                              ···· · · · ·- Further Redirect (McNally)· · · · · · · ·374
21·
  · · ··JOSEPH DOMINO                                          21·
                                                                 ·
 ···· · · · ·- Cross (Lawton - Continued)· · · · · · · ·103     ···· ··DANE A. WATSON
                                                               22·
                                                                 · · · · · ·- Direct (Williams)· · · · · · · · · · · ··376
22·
  · · · · · ·- Cross (VanMiddlesworth)· · · · · · · · ··115
                                                                ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·380
 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·131    23·
                                                                 · · · · · ·- Cross (Lawler)· · · · · · · · · · · · · ·397
23·
  · · · · · ·- Redirect (Wren)· · · · · · · · · · · · ··139     ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··403
 ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·143    24·
                                                                 · · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·410
24·
  · · · · · ·- Recross (VanMiddlesworth)· · · · · · · ··144     ···· · · · ·- Recross (Lawler)· · · · · · · · · · · · ·414
25·
  ·                                                            25·
                                                                 ·


                           KENNEDY REPORTING SERVICE, INC.
                                                 512.474.2233
                                                                                       Page 11 (Pages 1538-1541)
                                                                 Page 1538                                                       Page 1540
·1·· · · · · · · · ·MR. VanMIDDLESWORTH:··Yes.                               ·1··  ·generation.··So that would be in addition to the
·2·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··Do you see the chart                ·2··  ·twenty-nine eighty-nine and the thirty-three seventeen
·3·· ·at the bottom of Page 22?                                               ·3·· ·megawatt numbers purchased.
·4·· · · ·A· ··Yes.                                                           ·4·· · · ·Q· ··Okay.··So do you know about what the overall
·5·· · · ·Q· ··Okay.··What does that tell you about the amount                ·5·· ·growth in the overall generation is from year-to-year?
·6·· ·of capacity that Entergy is purchasing in what they call                ·6·· · · ·A· ··So if we take the purchases plus the owned
·7·· ·the "rate year" versus the test year?                                   ·7·· ·capacity and compare the two, the test year and the rate
·8·· · · ·A· ··That chart shows that as far as purchased                      ·8·· ·year, it's about a 7.8 percent change in overall
·9·· ·capacity is concerned that the Company anticipates that                 ·9·· ·capacity.
10·· ·it will need additional capacity or, roughly, if you                   10·· · · ·Q· ··By the way, for the rate year, you mentioned
11·· ·take it on average, the test year number, 35,863, is                   11·· ·something about the timing of the rate year.··What has
12·· ·about 2,989 megawatts per month, and the rate year would               12·· ·Entergy used for the rate year?
13·· ·go up to 39,807 which suggests an average amount of                    13·· · · ·A· ··So the rate year that Entergy uses is the
14·· ·purchases of 3,317 megawatts per month.                                14·· ·period -- I might get this wrong.··Let me look --
15·· · · ·Q· ··Can you give me the -- so the numbers you have                15·· ·June 2012 through May 2013.
16·· ·here are megawatt month numbers and you just converted                 16·· · · ·Q· ··And I guess that was what they used in their
17·· ·them to annual megawatt numbers?                                       17·· ·filing?
18·· · · ·A· ··Yes.                                                          18·· · · ·A· ··That's correct.
19·· · · ·Q· ··Can you give me the test year and rate year                   19·· · · ·Q· ··And since then, do you know if there's been any
20·· ·megawatts again, please?                                               20·· ·agreement about the implementation of rates in this
21·· · · ·A· ··2,989 test year; 3,317 rate year.                             21·· ·case?
22·· · · ·Q· ··And is that just third-party purchases, or does               22·· · · ·A· ··My understanding is that rates would become
23·· ·that include the effect of all the purchases?                          23·· ·effective on June 30th.··So that effectively moves the
24·· · · ·A· ··That's all the purchases.··So it's third-party,               24·· ·rate year up a month -- or back a month.
25·· ·affiliate and MSS-1.                                                   25·· · · ·Q· ··All right.

                                                                 Page 1539                                                       Page 1541
·1·· · · ·Q· ··And what are the MSS-1?                                       ·1··  · · · · · · · ·Now, you mentioned the importance of unit
·2·· · · ·A· ··The MSS-1 is the reserve equalization payments.               ·2··  ·costs.··The 300-plus megawatts of additional purchases,
·3·· ·So the Company takes service from the system.··So to the                ·3·· ·what does that go to?··I'm talking about the 300-plus
·4·· ·extent that the Company's owned resources or purchased                  ·4·· ·megawatts of the difference between the test year and
·5·· ·power resources are less than its obligation, then it                   ·5·· ·rate year.
·6·· ·will purchase capacity from the other operating                         ·6·· · · ·A· ··The utility will purchase additional capacity
·7·· ·companies.                                                              ·7·· ·mainly because it anticipates serving additional load.
·8·· · · ·Q· ··Is that firm or interruptible capacity?                        ·8·· · · ·Q· ··It would make sense to purchase additional
·9·· · · ·A· ··It's firm -- the system provides service to the                ·9·· ·capacity if you didn't and to have more capacity if you
10·· ·Company and those system resources are network                         10·· ·weren't planning on serving more load?
11·· ·resources; therefore, the power is considered firm.                    11·· · · ·A· ··No.
12·· · · ·Q· ··Is it -- but does each company operate                        12·· · · ·Q· ··Do you know whether that load is wholesale load
13·· ·separately, or is the system generation operated as a                  13·· ·or retail load?
14·· ·system?                                                                14·· · · ·A· ··I do not.
15·· · · ·A· ··The system agreement is what basically ties all               15·· · · ·Q· ··Does that matter for purposes of the unit cost
16·· ·six operating companies together as a single unit for                  16·· ·analysis?
17·· ·planning and operational purposes.··So for all things in               17·· · · ·A· ··No.
18·· ·effect, it's the system that's providing the service.                  18·· · · ·Q· ··Why not?
19·· · · ·Q· ··So, if you show that there's, I think, a little               19·· · · ·A· ··Because initially we're determining the
20·· ·more than 300 megawatts difference in purchases --                     20·· ·Company's overall revenue requirement which includes
21·· · · ·A· ··Yes.                                                          21·· ·retail and wholesale.··Ultimately, once you've
22·· · · ·Q· ··-- is there any difference in the -- I guess                  22·· ·established what that number is, then you've got to
23·· ·purchases aren't all of their generation capacity.··They               23·· ·separate the retail and the wholesale to set rates in
24·· ·have -- what else do they have?                                        24·· ·this case.
25·· · · ·A· ··ETI has about 1200 megawatts of owned                         25·· · · ·Q· ··So we've seen the number -- the proposed rate


                                  KENNEDY REPORTING SERVICE, INC.
                                                                 512.474.2233
                                                                                       Page 1 (Pages 1-4)
                                                     Page i                                                      Page iii
  · · · · · · · ··SOAH DOCKET NO. XXX-XX-XXXX
·1·                                                            ·1·
                                                                 · · · · · · · ·TABLE OF CONTENTS (CONTINUED)
 ···                                                           ·2·
                                                                 · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE
  · · · · · · · · · ·PUC DOCKET NO. 39896
·2·
 ···                                                           ·3·
                                                                 ·PRESENTATION ON BEHALF OF
  ·
·3·                                                             ··ENTERGY
                                                                   ·      TEXAS, INC. (CONTINUED)
 ···
  ·APPLICATION OF ENTERGY· ··)· ·STATE OFFICE OF
·4·                                                            ·4·
                                                                 ·
 ··TEXAS,
    ·     INC., FOR· · · · ··)
  ·AUTHORITY TO CHANGE RATES )
·5·                                                             ···· ··CHRIS E. BARRILLEAUX
 ··AND
    ·  RECONCILE FUEL COSTS, )                                 ·5·
                                                                 · · · · · ·- Direct (Olson)· · · · · · · · · · · · · ·149
  ·AND OBTAIN DEFERRED· · · ·)
·6·
 ··ACCOUNTING
    ·         TREATMENT· · ··) ADMINISTRATIVE HEARINGS          ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·151
  ·
·7·                                                            ·6·
                                                                 · · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··167
 ···
  ·
·8·                                                             ···· · · · ·- Redirect (Olson)· · · · · · · · · · · · ·187
 ···                                                           ·7·
                                                                 · · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·198
  ·
·9·
 ···                                                           ·8·
                                                                 · · ··SAMUEL C. HADAWAY
  ·
10·                                                             ···· · · · ·- Direct (Williams)· · · · · · · · · · · ··199
 ···
  · · · · · · · · · ·HEARING ON THE MERITS
11·                                                            ·9·
                                                                 · · · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·201
 ···
  · · · · · · · · ··Thursday, May 3, 2012
12·                                                             ···· · · · ·- Cross (Griffiths)· · · · · · · · · · · ··212
 ···                                                           10·
                                                                 · · · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·230
  ·
13·
 ···                                                            ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··231
  ·
14·                                                            11·
                                                                 · · · · · ·- Recross (Griffiths)· · · · · · · · · · ··239
 ···
  · · · · · · · · · ··TABLE OF CONTENTS
15·                                                            12·
                                                                 ·PROCEEDINGS RECESSED· · · · · · · · · · · · · · · · ·246
 ···                                                           13·
                                                                 ·
  · · · · ·(Volumes 1 through 8, Pages i through l)
16·
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                                                    Page ii                                                       Page iv
·1·
  · · · · · · · · · · ·TABLE OF CONTENTS                       ·1·
                                                                 · · · · · · · · ··TABLE OF CONTENTS
·2·
  · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE    ·2·
                                                                 · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE
·3·
  ·PROCEEDINGS, TUESDAY, APRIL 24, 2012 - VOL. 1· · · · ··5    ·3·
                                                                 ·PROCEEDINGS, WEDNESDAY, APRIL 25, 2012 - VOLUME 2· ··248
·4·
  ·OPENING STATEMENT ON BEHALF OF                              ·4·
                                                                 ·PRESENTATION ON BEHALF OF
 ··ENTERGY
    ·       TEXAS, INC. (Neinast)· · · · · · · · · · · · ·16    ··ENTERGY
                                                                   ·      TEXAS, INC. (CONTINUED)· · · · · · · · · · ··250
                                                               ·5·
                                                                 ·
·5·
  ·
                                                                ···· ··ROBERT D. SLOAN
 ··OPENING
    ·       STATEMENT ON BEHALF OF                             ·6·
                                                                 · · · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·250
·6·
  ·ENTERGY TEXAS, INC. (Wren)· · · · · · · · · · · · · ··22     ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·253
·7·
  ·OPENING STATEMENT ON BEHALF OF                              ·7·
                                                                 · · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·258
 ··CITIES
    ·      (Lawton)· · · · · · · · · · · · · · · · · · · ·37    ···· · · · ·- Redirect (Cyr)· · · · · · · · · · · · · ·285
·8·
  ·                                                            ·8·
                                                                 · · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·295
 ··OPENING
    ·       STATEMENT ON BEHALF OF                             ·9·
                                                                 · · ··H. VERNON PIERCE, JR.
·9·
  ·TEXAS INDUSTRIAL ENERGY CONSUMERS (VanMiddlesworth)· ·41     ···· · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·303
10·
  ·OPENING STATEMENT ON BEHALF OF                              10·
                                                                 · · · · · ·- Cross (Mack)· · · · · · · · · · · · · · ·305
 ··OFFICE
    ·      OF PUBLIC UTILITY COUNSEL (Ferris)· · · · · · ·49    ···· · · · ·- Cross (Younger)· · · · · · · · · · · · ··315
                                                               11·
                                                                 ·
11·
  ·
                                                                ···· ··MICHAEL P. CONSIDINE
 ··OPENING
    ·       STATEMENT ON BEHALF OF                             12·
                                                                 · · · · · ·- Direct (Neinast)· · · · · · · · · · · · ·317
12·
  ·STAFF (Smyth)· · · · · · · · · · · · · · · · · · · · ·52     ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·318
13·
  ·OPENING STATEMENT ON BEHALF OF                              13·
                                                                 · · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··352
 ··THE
    ·  UNITED STATES DEPARTMENT OF ENERGY (Porter)· · · ·54     ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·355
14·
  ·                                                            14·
                                                                 · · · · · ·- Redirect (Neinast)· · · · · · · · · · · ·358
15·
  ·PRESENTATION ON BEHALF OF                                    ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·362
 ··ENTERGY
    ·       TEXAS, INC.· · · · · · · · · · · · · · · · · ·60   15·
                                                                 ·
16·
  ·                                                             ··AFTERNOON
                                                                   ·        SESSION· · · · · · · · · · · · · · · · · ··365
 ···· ··JOSEPH DOMINO                                          16·
                                                                 ·
                                                                ··PRESENTATION
                                                                   ·           ON BEHALF OF
17·
  · · · · · ·- Direct (Wren)· · · · · · · · · · · · · · ·60    17·
                                                                 ·ENTERGY TEXAS, INC. (CONTINUED)· · · · · · · · · · ··366
 ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ··62    18·
                                                                 · · ··WALTER C. FERGUSON
18·
  ·                                                             ···· · · · ·- Direct (McNally)· · · · · · · · · · · · ·366
 ··AFTERNOON
    ·         SESSION· · · · · · · · · · · · · · · · · ··103   19·
                                                                 · · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·367
19·
  ·                                                             ···· · · · ·- Redirect (McNally)· · · · · · · · · · · ·369
 ··PRESENTATION
    ·            ON BEHALF OF                                  20·
                                                                 · · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·372
20·
  ·ENTERGY TEXAS, INC. (CONTINUED)                              ···· · · · ·- Further Redirect (McNally)· · · · · · · ·374
21·
  · · ··JOSEPH DOMINO                                          21·
                                                                 ·
 ···· · · · ·- Cross (Lawton - Continued)· · · · · · · ·103     ···· ··DANE A. WATSON
                                                               22·
                                                                 · · · · · ·- Direct (Williams)· · · · · · · · · · · ··376
22·
  · · · · · ·- Cross (VanMiddlesworth)· · · · · · · · ··115
                                                                ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·380
 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·131    23·
                                                                 · · · · · ·- Cross (Lawler)· · · · · · · · · · · · · ·397
23·
  · · · · · ·- Redirect (Wren)· · · · · · · · · · · · ··139     ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··403
 ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·143    24·
                                                                 · · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·410
24·
  · · · · · ·- Recross (VanMiddlesworth)· · · · · · · ··144     ···· · · · ·- Recross (Lawler)· · · · · · · · · · · · ·414
25·
  ·                                                            25·
                                                                 ·


                           KENNEDY REPORTING SERVICE, INC.
                                                 512.474.2233
                                                                                      Page 43 (Pages 1938-1941)
                                                            Page 1938                                                                  Page 1940

·1·· ·Frontier is a contract that is already in place.··It was          ·1·· · · · · · · · ·And for those reasons, this company could
·2·· ·in place during the test year.··All that remains to be            ·2·· ·not procure in a manner that was consistent with our
·3·· ·done is to ensure that the costs, because those costs             ·3·· ·general planning principles, as described by Mr. Cooper.
·4·· ·stepped up during the test year as well as the capacity           ·4·· ·And so for those reasons, we're now put in the position
·5·· ·stepped up during the test year, that those costs are             ·5·· ·of having to sort of make up.··It would be almost like
·6·· ·adequately adjusted for in the adjusted test year.                ·6·· ·if you missed a few mortgage payments, you still have to
·7·· · · · · · · · ·Another example is the Calpine contract.            ·7·· ·make those mortgage payments up.··And that's kind of
·8·· ·The Calpine contract does not increase the capacity of            ·8·· ·where -- the position we are in today, trying to
·9·· ·the Entergy system.··That is a contract that is already           ·9·· ·rebalance the company's portfolio in a way that's
10·· ·in place.··What will happen at the end of this month,             10·· ·consistent with those planning principles.
11·· ·that contract will be allocated differently to reflect            11·· · · ·Q· ··And can you explain -- do you have an idea of
12·· ·the fact that overhang of retail competition has been             12·· ·when the company on its current track would catch up and
13·· ·removed and now we are allocating modern and highly               13·· ·no longer become a short company?
14·· ·efficient, flexible generation to Entergy Texas; and              14·· · · ·A· ··No.··That -- that's a question --
15·· ·that allocation is consistent with those criteria that            15·· · · ·Q· ··But we're not there now?
16·· ·Mr. Cooper talked about in his testimony.                         16·· · · ·A· ··No, we certainly are not.
17·· · · · · · · · ·And so for those reasons, no, I don't               17·· · · ·Q· ··You had mentioned that the Calpine contract was
18·· ·believe that that example is consistent.                          18·· ·not brought for serving new load.··Does it nonetheless
19·· · · ·Q· ··And you mentioned in your answer -- and this             19·· ·provide benefits to customers?
20·· ·also came up, I think, from Mr. Lawton -- that ETI is             20·· · · ·A· ··Yes, sir, it does.··The Calpine contract -- and
21·· ·short.··Can you explain --                                        21·· ·that's the contract, as I mentioned, is already
22·· · · · · · · · ·MS. FERRIS:··Your Honor, I object.··This            22·· ·providing service to the system.··It's currently not
23·· ·is beyond the scope of my cross-examination.                      23·· ·allocated to ETI.··However, I believe it's -- at the end
24·· · · · · · · · ·JUDGE WALSTON:··Well, but there was also            24·· ·of this month, it will begin providing service to
25·· ·other cross before the lunch break.                               25·· ·Entergy Texas customers, a very attractive contract.··It

                                                            Page 1939                                                                  Page 1941

·1·· · · · · · · · ·MS. FERRIS:··Okay.··You're -- I'm sorry.            ·1·· ·has an attractive heat rate, a 7500 heat rate; and the
·2·· · · · · · · · ·JUDGE WALSTON:··Right.··Yeah.                       ·2·· ·cost of that contract, given, for instance, the fact
·3·· · · · · · · · ·MR. NEINAST:··I agree.                              ·3·· ·that it also displaces MSS-1 capacity, gas prices would
·4·· · · · · · · · ·JUDGE WALSTON:··No problem.                         ·4·· ·probably have to drop below a dollar per MMBtu for that
·5·· · · · · · · · ·MR. NEINAST:··It is beyond hers.                    ·5·· ·contract not to be economic.··In other words, at gas
·6·· · · · · · · · ·MS. FERRIS:··Sorry about that.                      ·6·· ·prices today, the fuel savings alone from that contract
·7·· · · ·Q· ··(BY MR. NEINAST)··Mr. Lawton had asked you, I            ·7·· ·pay for that contract over multiple times.
·8·· ·believe -- I believe it was Mr. Lawton -- about the               ·8·· · · ·Q· ··And that benefits ETI's customers?
·9·· ·company being short, and you had started to talk about            ·9·· · · ·A· ··Yes, sir, it does.
10·· ·why the company is short and it's been there -- can you           10·· · · ·Q· ··You might -- let me ask the question again; and
11·· ·go into more detail?··Why is the company short?··What is          11·· ·if you've already answered this question, then, please,
12·· ·it doing about it?                                                12·· ·you don't need to go any further into it.
13·· · · ·A· ··Yeah, and, you know, primarily, what -- what             13·· · · · · · · · ·But what I had written down, based on the
14·· ·happened is, we were required to go to retail                     14·· ·cross-examination, was some discussion you had with
15·· ·competition; and that requirement began in 1999 with              15·· ·Mr. VanMiddlesworth, and, I think, Mr. Lawton, asking
16·· ·the -- with the -- if I recall correctly, the objective           16·· ·you about whether the post-test year PPA costs can be
17·· ·to go to retail competition in 2002.··However, for a              17·· ·known and measurable?
18·· ·number of reasons, we were not able to do that, and so            18·· · · ·A· ··Yes, sir.
19·· ·we had this sort of constant overhang that we're going            19·· · · ·Q· ··Can you explain why the costs for those
20·· ·to go to retail competition by such-and-such date.                20·· ·contracts can be known and measurable?
21·· ·Constantly a moving target.··You really can't go out and          21·· · · ·A· ··I'll try.
22·· ·procure long-term cash capacity.··You really can't go             22·· · · · · · · · ·The costs in question here -- and I sort
23·· ·out and build a new highly efficient, modern generating           23·· ·of ticked off a number of these.··One of them is the
24·· ·plant in a world where your customers could be severed            24·· ·Frontier contract.··That Frontier contract has probably
25·· ·by someone else in the very near future.                          25·· ·been in place -- I don't -- close to a decade, perhaps.


                                KENNEDY REPORTING SERVICE, INC.
                                                            512.474.2233
                                                                                       Page 44 (Pages 1942-1945)
                                                              Page 1942                                                                   Page 1944

·1·· ·Not long after the plant was completed, we began                    ·1·· ·is, one of the routine sort of adjustments that are made
·2·· ·contracting for it.                                                 ·2·· ·are, for instance, merit increases for employees.··And
·3·· · · · · · · · ·What we're talking about here is that                 ·3·· ·so that's measured -- a known and measurable change.
·4·· ·contract stepping up from -- I believe it's                         ·4·· ·The fact of the matter is, the day after that
·5·· ·150 megawatts up to 300 megawatts.··And so all that                 ·5·· ·implementation of that merit increase or the acceptance
·6·· ·needs to be done is to recognize those additional costs             ·6·· ·of that as a known and measurable change, an employee
·7·· ·because that step-up occurs in the -- in the midst of               ·7·· ·could resign from the company; and, therefore, the costs
·8·· ·the test year.··It doesn't occur through the entire test            ·8·· ·would deviate.··But, in general, those cost changes are
·9·· ·year, so it doesn't fully recognize the cost of that                ·9·· ·known, they are measurable, and those little deviations
10·· ·contract.··That contract is needed to serve load today,             10·· ·are just not that much a significant part of the
11·· ·and because we have quite a bit of experiences, we have             11·· ·outcome.
12·· ·a good understanding of what the costs are today and                12·· · · ·Q· ··And, finally, on this purchased power topic,
13·· ·what the costs will be in the future.                               13·· ·you'd discussed the Frontier contract, the Calpine
14·· · · · · · · · ·Similarly, Calpine, we have -- that is a              14·· ·contract.··I think there's another, the SRMPA?
15·· ·contract that we have some experience with as well.··The            15·· · · ·A· ··Yes, sir.
16·· ·capacity costs are well known.··It's based upon our                 16·· · · ·Q· ··Was there anything about that contract that --
17·· ·experience and based upon a negotiated contract.··I                 17·· · · ·A· ··With the SR --
18·· ·understand that there could be instances, as indicated              18·· · · ·Q· ··-- makes it not known and measurable?
19·· ·by Mr. VanMiddlesworth, that there could be some                    19·· · · ·A· ··Well, the SRMPA has a very straightforward $3
20·· ·deviations from the actual payments made.··But, you                 20·· ·per kW a month stated rate.··So it's very easy to
21·· ·know, the history there is those are very, very small               21·· ·calculate what those known and measurable costs are.
22·· ·deviations from the actual contracted costs.                        22·· · · ·Q· ··My next topic -- almost done -- is MSS-1.··You
23·· · · · · · · · ·When we negotiate those contracts, our                23·· ·were asked some questions by -- I think it was
24·· ·intent is to get the full benefit of that capacity.                 24·· ·Mr. VanMiddlesworth.··Generally, I mean, to cut to the
25·· ·Those provisions are generally intended to enforce and              25·· ·chase, there was discussion of maintaining test year

                                                              Page 1943                                                                   Page 1945
·1·· ·make sure that we get the full benefits of that                     ·1·· ·loads by taking into account rate year costs.··In the
·2·· ·capacity.··The counterparties intend to get the full                ·2·· ·course of that discuss -- and Mr. VanMiddlesworth was
·3·· ·benefit of those capacity costs.··They want to make sure            ·3·· ·asking you for some analyses in doing different things
·4·· ·that in the event they do have an outage or need to take            ·4·· ·with Entergy Arkansas.··I remember that.
·5·· ·the unit off-line, that it's done in a way that's                   ·5·· · · ·A· ··Yes, sir.
·6·· ·consistent so they can continue to get paid their full              ·6·· · · ·Q· ··But in the course of that discussion, you said
·7·· ·capacity.                                                           ·7·· ·something about an analysis by Mr. Cooper that involved
·8·· · · · · · · · ·So, for those reasons, we have a need --              ·8·· ·4.5 million.··What was that -- what was that?
·9·· ·we know what those costs are.··They are measurable, and             ·9·· · · ·A· ··Yes, sir.··That is extremely relevant.
10·· ·I think that is consistent with the known and measurable            10·· · · · · · · · ·The situation that was being described by
11·· ·standard.                                                           11·· ·Mr. VanMiddlesworth is what if EAI had higher load,
12·· · · ·Q· ··Well, and also you mentioned inconsistencies               12·· ·would that result -- in the test -- in the rate year,
13·· ·among contracts.··If a contract -- go back to some --               13·· ·what if they had higher load?··What if ETI had higher
14·· ·not the contract we're talking about here, but some                 14·· ·load?··What if they had lower load?
15·· ·contract that's already in base rates.                              15·· · · · · · · · ·Mr. Cooper examined that very situation.
16·· · · · · · · · ·Once it's in base rates, does that mean               16·· ·What he did is he locked in the responsibility ratios,
17·· ·there are no inconsistencies in the costs going forward,            17·· ·and what I mean by that is the actual load that was in
18·· ·or those fluctuate so it's not absolutely without doubt             18·· ·the test year was locked in via those responsibility
19·· ·known that it is fixed and never going to change during             19·· ·ratios.··And then he measured for that rate year, what
20·· ·its life?                                                           20·· ·would have been the difference in cost for MSS-1 if
21·· · · ·A· ··Well, while those fluctuations are rather                  21·· ·nothing changed with regard to those -- that load
22·· ·small, the fact is, even those contracts in base rates              22·· ·growth.··No operating company deviated whatsoever.··They
23·· ·can fluctuate.··It's just that there's not any real                 23·· ·actually used the test year load.··The result of that
24·· ·significant deviation from that.                                    24·· ·was approximately $4.5 million reduction in our MSS-1
25·· · · · · · · · ·And another example of this, in my mind               25·· ·cost as a result of locking in those loads.


                                  KENNEDY REPORTING SERVICE, INC.
                                                               512.474.2233
                                                                                            Page 45 (Pages 1946-1949)
                                                                 Page 1946                                                                 Page 1948

·1··  · · · · · · · ·MR. NEINAST:··No further questions.                     ·1·· · · · · · · · · · ·RECROSS-EXAMINATION
·2··  · · · · · · · · ··CLARIFYING EXAMINATION                               ·2·· ·BY MR. LAWTON:
 ·3·· ·BY JUDGE WALSTON:                                                     ·3·· · · ·Q· ··Mr. May, you would agree that the company has
 ·4·· · · ·Q· ··Okay.··I want to ask a couple of clarifying                  ·4·· ·had load growth over the past number of years?
 ·5·· ·questions, if I can, and I may just show my lack of                   ·5·· · · ·A· ··Yes, sometimes --
 ·6·· ·understanding.                                                        ·6·· · · ·Q· ··Some years --
 ·7·· · · · · · · · ·But if I understood your testimony, the                 ·7·· · · ·A· ··-- load growth, sometimes no.
 ·8·· ·new purchased power contracts are being -- or have been               ·8·· · · ·Q· ··Okay.··And you would agree that the -- between
 ·9·· ·entered into to account for the shortage of capacity.                 ·9·· ·the test year and the rate year, the company is
10·· ·Correct?                                                               10·· ·projecting load to grow?
11·· · · ·A· ··Yes, sir.                                                     11·· · · ·A· ··Yes, sir.
12·· · · ·Q· ··Okay.··And not for load growth.··Correct?                     12·· · · ·Q· ··Okay.··And if load growth occurs and the
13·· · · ·A· ··Yes.··In this case, the needs that are driven                 13·· ·company does not buy any additional capability, what
14·· ·by the allocation -- for instance, Calpine.··That is a                 14·· ·happens?··Does it become more short?
15·· ·contract that already exists on the system.··What is                   15·· · · ·A· ··That would depend upon what happens with the
16·· ·happening right now, none of that comes to ETI.··But                   16·· ·other operating companies.
17·· ·what will happen is, 50 percent of that will be                        17·· · · ·Q· ··Fair enough.··All else equal, to use one of
18·· ·allocated to ETI.··The other 50 percent will be to                     18·· ·Mr. VanMiddlesworth's phrases.
19·· ·Entergy Gulf States Louisiana.··That is essentially                    19·· · · ·A· ··To the extent that load grows and we do not add
20·· ·recognizing the fact that this company now has some                    20·· ·capacity, it is an accurate statement that the company
21·· ·resolution less uncertainty about what its future is,                  21·· ·will become more short.
22·· ·and so it's allocating long-term contracts to meet its                 22·· · · ·Q· ··Okay.··So we know that load grows from year to
23·· ·needs.                                                                 23·· ·year, or it's projected.··Correct?
24·· · · ·Q· ··But what I was leading up to is that capacity                 24·· · · ·A· ··Certainly a possibility.
25·· ·is added, then the MSS-1 costs would go down?                          25·· · · ·Q· ··All right.··And is some of the purchased power

                                                                 Page 1947                                                                 Page 1949

·1·· · · ·A· ··Yes, sir.                                                     ·1·· ·here in this case being purchased to replace contracts
·2·· · · ·Q· ··Okay.                                                         ·2·· ·that are dropping off in the test year, or do you know?
·3·· · · ·A· ··It is a very straightforward calculation.                     ·3·· · · ·A· ··That direct relationship, I can't speak to.
·4·· · · ·Q· ··Okay.··And actually, that's all I want to know.               ·4·· · · ·Q· ··That's something I'd ask Mr. Cooper?
·5·· · · · · · · · ·But just can you tell me, just in ballpark               ·5·· · · ·A· ··You certainly can.··But certainly, it's a fact
·6·· ·amounts, is the increase and the decrease, is that a                   ·6·· ·that there are changes in the overall makeup.
·7·· ·wash or is one more or less?                                           ·7·· · · ·Q· ··Fair enough.
·8·· · · ·A· ··It depends on the contract, sir.··For instance,               ·8·· · · · · · · · ·MR. LAWTON:··Your Honor, I pass the
·9·· ·the Calpine contract is priced higher than MSS-1.··Now,                ·9·· ·witness.··Thank you.
10·· ·when you look at our rate year MSS-1 calculation, it                   10·· · · · · · · · ·Thank you, Mr. May.
11·· ·includes all that that you just identified there.··All                 11·· · · · · · · · ·JUDGE WALSTON:··TIEC?
12·· ·of that capacity results, and that's what's reflected in               12·· · · · · · · · ·MR. VanMIDDLESWORTH:··Yes.
13·· ·our rate year, lower MSS-1 cost.                                       13·· · · · · · · · · · ··RECROSS-EXAMINATION
14·· · · · · · · · ·And in the case of Calpine, it has higher                14·· ·BY MR. VanMIDDLESWORTH:
15·· ·cost per kW than MSS-1 costs would be.··So the net cost                15·· · · ·Q· ··Following up on Judge Walston's questions, ETI
16·· ·of that contract -- net after the fact that MSS-1 goes                 16·· ·in this filing shows that it's projecting to purchase
17·· ·down -- is still a positive value.··That's reflected in                17·· ·about 600 megawatts more capacity in the rate year,
18·· ·our rate year clause.                                                  18·· ·third-party purchases, than in the test year.··Is that
19·· · · · · · · · ·In the case of SRMPA, this is a contract.                19·· ·right?
20·· · · ·Q· ··You've gone beyond my -- I got the answer that                20·· · · ·A· ··Let me think about that for a moment.··How much
21·· ·I wanted.                                                              21·· ·is the number again?
22·· · · ·A· ··Thank you.                                                    22·· · · ·Q· ··About 600 megawatts.
23·· · · ·Q· ··But I appreciate it.                                          23·· · · ·A· ··It's probably approaching 600.
24·· · · · · · · · ·JUDGE WALSTON:··Okay.··Further cross?                    24·· · · ·Q· ··Okay.··And ETI is also projecting to purchase
25·· · · · · · · · ·MR. LAWTON:··I do.··Thank you, Your Honor.               25·· ·about 300 megawatts less of MSS-1 capacity in the rate


                                  KENNEDY REPORTING SERVICE, INC.
                                                                 512.474.2233
                                                                                       Page 46 (Pages 1950-1953)
                                                               Page 1950                                                               Page 1952

·1·· ·year than in the test year.··Correct?                                ·1··  ·including MSS-1, ETI is proposing to add about
·2·· · · ·A· ··I can't tell you the specific amount, sir.                  ·2··  ·300 megawatts more in the rate year than in the test
·3·· · · ·Q· ··You don't know?                                              ·3·· ·year.··Right?
·4·· · · ·A· ··I don't have that document in front of me.                   ·4·· · · ·A· ··If you put that in an exhibit, I can confirm
·5·· · · ·Q· ··Okay.··You know it's a lot less than the amount              ·5·· ·that.··I don't know the number precisely.
·6·· ·of purchased capacity?                                                ·6·· · · ·Q· ··Okay.··We can -- that's a -- we could get that
·7·· · · ·A· ··Absolutely, for the very reasons we discussed.               ·7·· ·from, I think, H-12 in the rate filing, couldn't we?
·8·· · · ·Q· ··Oh, and those --                                             ·8·· · · ·A· ··I'm sorry.
·9·· · · ·A· ··Those reasons being that as you add capacity,                ·9·· · · ·Q· ··We could do that calculation from H-12?··I'm
10·· ·that the MSS-1 amounts would be reduced.                             10·· ·not going to make you do the calculation.··I think it's
11·· · · ·Q· ··Right.··But why wouldn't they be reduced by the             11·· ·in the record.
12·· ·same amount of the capacity you're adding?                           12·· · · ·A· ··Okay.
13·· · · ·A· ··There would be a number of reasons why that                 13·· · · ·Q· ··You don't have any reason to disagree?
14·· ·would be.··One of the primary reasons would be the fact              14·· · · ·A· ··No.··I believe that's right.··The company will
15·· ·that the system has other changes.··There are capacity               15·· ·be adding capacity.··Correct.
16·· ·being acquired on the other operating companies as well.             16·· · · ·Q· ··All right.··And when you add -- when a company
17·· ·We will be acquiring capacity at Arkansas and                        17·· ·adds capacity, they need -- if a company is planning on
18·· ·Mississippi, I believe.··Those will likely occur this                18·· ·experiencing load growth, it needs to add a little more
19·· ·year.                                                                19·· ·in capacity than the estimated load growth.··Right?
20·· · · ·Q· ··And you're saying the capacity acquired by                  20·· ·Talking about reserve margins.
21·· ·Arkansas and Mississippi means that the MSS-1 won't                  21·· · · ·A· ··If the -- okay.··I'm sorry.
22·· ·decrease as much as the purchased capacity for ETI?                  22·· · · · · · · · ·To the extent that you have a hundred
23·· · · ·A· ··All things being relative.                                  23·· ·megawatts of load growth, planning principles would
24·· · · ·Q· ··All right.··And so you -- do you dispute that               24·· ·suggest, if the company was perfectly balanced in the
25·· ·ETI projects, when you add all the purchased capacity,               25·· ·first place, that they should add, for instance, 115.

                                                               Page 1951                                                               Page 1953

·1·· ·purchased -- all the purchased capacity, third party,                ·1·· · · ·Q· ··Right.··And the 115 is the reserve --
·2·· ·and we sometimes -- by the way, when we talk -- when you             ·2·· · · ·A· ··Reserve margin.
·3·· ·use the term "short," you're not talking about all                   ·3·· · · ·Q· ··And that's built into your rates.··I mean,
·4·· ·purchased capacity as we use the term for the purchased              ·4·· ·everybody that buys a megawatt from you is buying -- is
·5·· ·power rider.··Right?··You're talking about a subset of               ·5·· ·paying for the reserve margin as a part of the rate?
·6·· ·that.                                                                ·6·· · · ·A· ··Theoretically.
·7·· · · ·A· ··I'm not sure I understand the question.··I'm                ·7·· · · ·Q· ··All right.
·8·· ·sorry.                                                               ·8·· · · ·A· ··It should include that.
·9·· · · ·Q· ··When you say they're short, when ETI is short,              ·9·· · · ·Q· ··All right.··So 300 megawatts of additional
10·· ·don't you mean that if you look at just the purchased                10·· ·purchased capacity would serve a little less than
11·· ·power and the legacy contracts and the other affiliate               11·· ·that -- I'm not going to -- can't do the math right
12·· ·contracts, that that -- and you don't look at MSS-1, you             12·· ·here -- of actual load growth?
13·· ·just look at the stuff either owned or purchased                     13·· · · ·A· ··You know, I'm not sure I can agree with that
14·· ·directly by ETI, that that's not sufficient to meet                  14·· ·without seeing the facts.
15·· ·their load?                                                          15·· · · ·Q· ··Okay.··Well, you may be able to do that.··If
16·· · · ·A· ··That's correct.                                             16·· ·somebody said, "Phillip May, I need -- we're going to
17·· · · ·Q· ··And then you have to add -- and then the way                17·· ·have a hundred megawatts of load growth next year, and
18·· ·that ETI becomes not short anymore is it purchases                   18·· ·we need the capacities -- you need to get capacity to
19·· ·MSS-1.                                                               19·· ·meet that," how many megawatts capacity would you need,
20·· · · ·A· ··Yes, I think that's a reasonably accurate                   20·· ·more or less, to do that?
21·· ·statement.                                                           21·· · · ·A· ··Depends on a number of factors.··But if this
22·· · · ·Q· ··Okay.··I think sometimes the record -- it's                 22·· ·were a standalone company, it would probably add
23·· ·probably partially my fault.··Sometimes the record has               23·· ·20 percent more than that hundred.
24·· ·gotten a little fuzzy about what that means.                         24·· · · ·Q· ··Okay.··A little -- and that's the reserve
25·· · · · · · · · ·Now, but all in, all purchased capacity,               25·· ·margin?


                                  KENNEDY REPORTING SERVICE, INC.
                                                               512.474.2233
                                                                                       Page 47 (Pages 1954-1957)
                                                            Page 1954                                                                  Page 1956

·1·· · · ·A· ··Yes.                                                     ·1·· ·attractive.
·2·· · · ·Q· ··Okay.··Now, you've previously taken the                  ·2·· · · ·Q· ··But the fallback proposal did not deal with
·3·· ·position that it was appropriate in looking at the rate           ·3·· ·load growth or load shrinkage or whatever happened.··It
·4·· ·year purchased power to take load growth into account to          ·4·· ·just stuck with the test year sales?
·5·· ·make sure that ETI doesn't over-recover, haven't you?             ·5·· · · ·A· ··Yes, sir, the fallback proposal is consistent
·6·· · · ·A· ··Are you referring to the incremental capacity            ·6·· ·with the current ratemaking in the PUCT.
·7·· ·rider testimony?                                                  ·7·· · · ·Q· ··Well, I was just --
·8·· · · ·Q· ··No.··I'm referring to actually the position you          ·8·· · · · · · · · ·MR. VanMIDDLESWORTH:··I'm going to take
·9·· ·originally filed in this case.                                    ·9·· ·issue with that and move to strike the volunteering that
10·· · · ·A· ··Which was with regard to a capacity rider.               10·· ·its current -- consistent with current practice at the
11·· ·Correct?                                                          11·· ·PUC.
12·· · · ·Q· ··I'm just -- and in that -- in your initial               12·· · · · · · · · ·MR. NEINAST:··I object.··He opened up the
13·· ·proposal, it was your position that the -- you should             13·· ·question by going back to the exhibit.
14·· ·take load growth into account, revenue growth into                14·· · · · · · · · ·MR. VanMIDDLESWORTH:··My question was
15·· ·account, in addition to costs.                                    15·· ·simply, is this what you proposed?··His answer was --
16·· · · ·A· ··Yes.··In my original testimony, I indicated              16·· ·I'm not sure if he said yes, but then he said, "And
17·· ·that we would true that capacity up.··The only way to do          17·· ·that's consistent with PUCT practice."
18·· ·that is to consider load growth.                                  18·· · · · · · · · ·MR. NEINAST:··But it --
19·· · · ·Q· ··And you indicated that if revenues collected             19·· · · · · · · · ·JUDGE WALSTON:··I think his answer -- you
20·· ·from the rider, which is how you proposed it, were                20·· ·asked another question about, well, what you're doing
21·· ·increased due to sales, then that would automatically be          21·· ·now in base rates, and he was responding to the base
22·· ·reflected in updates to the rider via over or under               22·· ·rate question.
23·· ·recovery?                                                         23·· · · · · · · · ·MR. VanMIDDLESWORTH:··Oh, okay.
24·· · · ·A· ··Yes, sir, that would be part of the                      24·· · · · · · · · ·JUDGE WALSTON:··Yeah.
25·· ·reconciliation process.                                           25·· · · · · · · · ·MR. VanMIDDLESWORTH:··Let me withdraw my

                                                            Page 1955                                                                  Page 1957

·1·· · · ·Q· ··So this problem we've talked about here under            ·1·· ·motion to strike.
·2·· ·the purchased power rider, as you proposed it, if this            ·2·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··Are you aware of any
·3·· ·hypothetical utility was adding --                                ·3·· ·prior PUC decision where the PUC has said, "We're going
·4·· · · ·A· ··Yes, sir.                                                ·4·· ·to look out two years past the test year and estimate
·5·· · · ·Q· ··-- a hundred dollars to meet an expected                 ·5·· ·purchased power costs and then apply those to test year
·6·· ·10 percent load --                                                ·6·· ·billing determinants"?··Any other PUC case ever in
·7·· · · ·A· ··Yes, sir.                                                ·7·· ·Texas?
·8·· · · ·Q· ··-- increase on TIEC Exhibit 23 and that's what           ·8·· · · ·A· ··Well, I think a number of these cases have been
·9·· ·they had --                                                       ·9·· ·settled, so that would be hard to say.
10·· · · ·A· ··Yes, sir.                                                10·· · · ·Q· ··Are you aware of any PUC decision?
11·· · · ·Q· ··-- then there would be no over or under                  11·· · · ·A· ··I -- I can't recall any specific PUCT finding
12·· ·recovery because it would be trued up?                            12·· ·on that.
13·· · · ·A· ··That's right.                                            13·· · · ·Q· ··I mean, this -- we're treading new ground.
14·· · · ·Q· ··But when the Commission rejected your purchased          14·· ·This -- what you proposed here has never been done by
15·· ·capacity rider in this case, your position after that             15·· ·this commission, has it?
16·· ·was, "Well, just take the purchased capacity costs and            16·· · · ·A· ··I don't agree.
17·· ·apply it to test year sales"?                                     17·· · · ·Q· ··Okay.··Then tell me when this commission has
18·· · · ·A· ··Well, I think our position was kind of an                18·· ·ordered the use of test year -- or of rate year
19·· ·either/or.··We represented that had we not had a                  19·· ·purchased capacity and test year sales numbers.
20·· ·capacity -- if we did not get a capacity rider, then you          20·· · · ·A· ··In my mind, this is really not different than a
21·· ·would use these for base rates.                                   21·· ·merit increase adjustment.··It's known; it's measurable.
22·· · · ·Q· ··Right.··Right.··And I'm showing that the                 22·· ·Sure, it extends beyond the test year, but in this case,
23·· ·initial proposal dealt with this, and you thought that            23·· ·the capacity that this company must add is not being
24·· ·was a reasonable thing to do.                                     24·· ·added because we have some great load growth
25·· · · ·A· ··I think the initial proposal is still very               25·· ·expectation.


                                  KENNEDY REPORTING SERVICE, INC.
                                                            512.474.2233
                                                                                           Page 48 (Pages 1958-1961)
                                                                Page 1958                                                                 Page 1960
·1·· · · ·Q· ··I'm just asking --                                           ·1·· ·contract was in place, that there were never ever two
·2·· · · ·A· ··And I'm answering the question, sir.                         ·2·· ·months that had the same capacity payment from ETI to
·3·· · · · · · · · ·JUDGE WALSTON:··I think you went beyond                 ·3·· ·Frontier?
·4·· ·his question.                                                         ·4·· · · ·A· ··I don't have that data in front of me, but I
·5·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··Yeah.··My question,                ·5·· ·don't believe that there are huge variations in the
·6·· ·sir, is, tell me the case where there's a PUC decision                ·6·· ·capacity cost.··Now, it is a shaped product --
·7·· ·that says, "We will look two years out for purchased                  ·7·· · · ·Q· ··My question --
·8·· ·capacity and come up with a projection of that and apply              ·8·· · · · · · · · ·JUDGE WALSTON:··Okay.
·9·· ·it to test year sales."··Tell me the case.                            ·9·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··Can you answer my
10·· · · ·A· ··Sir, I can't point to specific language in a                 10·· ·question?
11·· ·PUCT finding.                                                         11·· · · · · · · · ·JUDGE WALSTON:··Try and just answer his
12·· · · ·Q· ··Can you point to any language about purchased                12·· ·question as concisely as you can.
13·· ·power capacity that does that?                                        13·· · · · · · · · ·WITNESS MAY:··I'm sorry.
14·· · · ·A· ··No.                                                          14·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··We won't badger each
15·· · · · · · · · ·MR. NEINAST:··Objection, badgering the                  15·· ·other.
16·· ·witness.                                                              16·· · · · · · · · ·Do you -- isn't it a fact that for the
17·· · · · · · · · ·JUDGE WALSTON:··I don't know that he's                  17·· ·entire ten months that contract was in place, there were
18·· ·badgering, but I think he's already told you before he                18·· ·no two months that had the same capacity payment from
19·· ·doesn't know --                                                       19·· ·ETI, if you know?
20·· · · · · · · · ·MR. VanMIDDLESWORTH:··Okay.                             20·· · · ·A· ··I don't have the contract in front of me,
21·· · · · · · · · ·JUDGE WALSTON:··-- a finding or a case.                 21·· ·but --
22·· ·So it's repetitive, if nothing else.                                  22·· · · ·Q· ··I'm just asking you --
23·· · · · · · · · ·MR. VanMIDDLESWORTH:··I haven't had an                  23·· · · ·A· ··-- on a dollar basis, I would suspect that
24·· ·objection levied against me in years, Your Honor.··I                  24·· ·that's correct.
25·· ·thought the witness was badgering me.                                 25·· · · ·Q· ··All right.··And, in fact, weren't there

                                                                Page 1959                                                                 Page 1961
·1·· · · · · · · · ·(Laughter)                                              ·1·· ·adjustments made for availability during the test year
·2·· · · · · · · · ·MR. NEINAST:··But you asked the question.               ·2·· ·for --
·3·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··Let me go to another               ·3·· · · ·A· ··I suspect --
·4·· ·subject.                                                              ·4·· · · ·Q· ··-- the Frontier contract?
·5·· · · · · · · · ·You mentioned a Frontier contract, and it               ·5·· · · ·A· ··Yes, sir.··I suspect there could have been.
·6·· ·was actually in place during the test year?                           ·6·· · · ·Q· ··And, in fact, weren't there months where the
·7·· · · ·A· ··Yes.                                                         ·7·· ·payments under the Frontier contract were about half of
·8·· · · ·Q· ··And that it was at a lower megawatt level.                   ·8·· ·the full contract amount?
·9·· ·Right?                                                                ·9·· · · ·A· ··I'm not familiar with that, but it is a shaped
10·· · · ·A· ··Yes.··It straddled the test year, so there was               10·· ·product.
11·· ·an increase in the capacity and the cost that was in the              11·· · · ·Q· ··Yes.
12·· ·midst of the test year.                                               12·· · · ·A· ··And that may be driving that.
13·· · · ·Q· ··Okay.··And I'm going to try to avoid asking you              13·· · · ·Q· ··Yes.··So in some months, all other things being
14·· ·anything that's highly sensitive.··We know there's a                  14·· ·equal, even if they performed completely --
15·· ·Frontier contract.                                                    15·· · · ·A· ··Yes, sir.
16·· · · ·A· ··Yes, sir.                                                    16·· · · ·Q· ··-- there would be higher capacity costs than
17·· · · ·Q· ··I think we may know the megawatts, but I'm not               17·· ·others?
18·· ·sure.··So I'm going to try to avoid that.                             18·· · · ·A· ··Yes, sir.
19·· · · · · · · · ·But for the first ten months of the test                19·· · · ·Q· ··But, in fact, for the Frontier contract, in the
20·· ·year, the Frontier contract was in one level, and then                20·· ·test year, there were months when -- I mean, if that
21·· ·it went to another level.                                             21·· ·were the case, there were a number of months that had
22·· · · ·A· ··Yes, sir.                                                    22·· ·the same percentage applicable.··Right?··June, July,
23·· · · ·Q· ··Now, you talked about the stability of that                  23·· ·August, September all have the same?
24·· ·contract, but isn't it the fact -- a fact that for the                24·· · · ·A· ··Yes, sir.
25·· ·first ten months of the test year, when that Frontier                 25·· · · ·Q· ··And so everybody knows what we're talking about


                                     KENNEDY REPORTING SERVICE, INC.
                                                                512.474.2233
II                                                                  II
                    SOAH DOCKET NO. XXX-XX-XXXX
                      PUC DOCKET NO. 39896




     APPLICATION OF ENTERGY TEXAS,      §
     INC. FOR AUTHORITY TO CHANGE       § BEFORE THE STATE OFFICE
     RA TES, RECONCILE FUEL COSTS,      §          OF
     AND OBTAIN DEFERRED                § ADMINISTRATIVE HEARINGS
     ACCOUNTING TRFATMENT               §




                 DIRECT TESTIMONY AND EXHIBITS

                                 OF

                         MARK E. GARRETT



                           ON BEHALF OF

               CITIES SERVED BY ENTERGY TEXAS, INC.




                          MARCH 27, 2012




                            Mark Garrett
                         Garrett Group, LLC
                       Oklahoma City, Oklahoma
Blank Page
                                                TABLE OF CONTENTS



Section I.       Witness Identification ........................................................................................... 3

Section II.      Purpose of Testimony ............................................................................................ 4

Section III.     Rate Base Adjustments

                 A. FIN 48 Tax Adjustment .................................................................................. 5
                 B. Prepaid Pension Costs in Rate Base ............................................................... 7
                 C. Rita Regulatory Asset .................................................................................... 11

Section IV.      Payroll and Benefits Expense Adjustments

                 A.   ET! Payroll Adjustment ............................................................................... 12
                 B.   ESI Payroll Adjustment ................................................................................ 19
                 C.   Lewis Creek and Sabine Payroll Adjustments ........................................... 23
                 D.   Above-Market Payroll Cost Adjustments ................................................... 25
                 E.   Incentive Compensation Adjustment ........................................................... 27
                 F.   Supplemental Executive Retirement Compensation .................................. 54
                 G.   Above-Market Benefit Costs Adjustment .................................................. 58
                 H.   Ad Valorem Tax Expense Adjustment ....................................................... 60

Section V.       MISO Transition Expense Adjustment ............................................................ 61

Section VI.      River Bend Decommissioning Expense Adjustment ....................................... 64

Exhibit MG-1 Qualifications of Mark E. Garrett ......................................................... Attached

Exhibit MG-2 Garrett Adjustment Workpapers .......................................................... Attached




Direct Testimony of Mark E. Garrett                                                                       Page 2 of 58
Docket No. 39896
Blank Page
     SECTION I. WITNESS IDENTIFICATION

 1   Q:      PLEASE STATE YOUR NAME AND OCCUPATION.

 2   A:      My name is Mark Garrett and I am the President of Garrett Group, LLC, a firm

 3           specializing in public utility regulation, litigation and consulting services.

 4

 5   Q:      WOULD YOU PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND

 6           AND     YOUR       PROFESSIONAL           EXPERIENCE         RELATED         TO    UTILITY

 7           REGULATION?

 8   A:      I am an attorney and a certified public accountant. I work as a consultant in the area of

 9           public utility regulation.    I received my bachelor's degree from the University of

10           Oklahoma and completed post graduate hours at Stephen F. Austin State University and

11           at the University of Texas at Arlington and Pan American. I received my juris doctorate

12           degree from Oklahoma City University Law School and was admitted to the Oklahoma

13           Bar in 1997. I am a Certified Public Accountant licensed in the States of Texas and

14           Oklahoma with a background in public accounting, private industry, and utility

15           regulation. In public accounting, as a staff auditor for a firm in Dallas, I primarily

16           audited financial institutions in the State of Texas. In private industry, as controller for a

17           mid-sized ($300 million) corporation in Dallas, I managed the Company's accounting

18           function, including general ledger, accounts payable, financial reporting, audits, tax

19           returns, budgets, projections, and supervision of accounting personnel.             In utility

20           regulation, I served as an auditor in the Public Utility Division of the Oklahoma

21           Corporation Commission from 1991 to 1995. In that position, I managed the audits of

     Direct Testimony of Mark E. Garrett                                                Page 3 of65
     Docket No. 39896
 l           major gas and electric utility companies in Oklahoma. Since leaving the Commission, I

 2           have worked on various rate cases and other regulatory proceedings on behalf of

 3           industrial interveners, gas pipelines and the Attorney General of Oklahoma.

 4

 5   Q:      HAVE YOUR QUALIFICATIONS BEEN ACCEPTED IN PROCEEDINGS

 6           DEALING WITH COST-OF-SERVICE AND OTHER RATEMAKING ISSUES?

 7   A:      Yes, they have.      A more complete description of my qualifications and a list of the

 8           proceedings in which I have been involved are included at the end of my testimony.

 9

10   Q:      ON WHOSE BEHALF ARE YOU APPEARING IN THESE PROCEEDINGS?

11   A:      I am appearing on behalf of Certain Cities Served by Entergy Texas, Inc. ("Cities"). 1




     SECTION II.              PURPOSE OF TESTIMONY

12   Q:      WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING?

13   A:      The purpose of my testimony is to address various revenue requirement issues identified

14           in the Company's rate case application and to provide the Commission with

15           recommendations for the resolution of these issues. I address several rate base issues,

16           including the Company's Prepaid Pension Asset, the Rita Regulatory Asset, Uncertain

17           Tax Positions, and several operating expense issues, including Payroll Expense,

18           Incentive    Compensation,       Employee      Benefits    Expense,      Supplemental      Executive


     1
       Cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Dayton, Groves, Houston, Huntsville,
     Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest, Pinehurst, Port Arthur, Port Neches,
     Rose City, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and West Orange.
     Direct Testimony of Mark E. Garrett                                                       Page 4 of 65
     Docket No. 39896
 l              Retirement Expense, Ad Valorem Tax Expense, MISO Transition Costs and River Bend

 2              Decommissioning Costs. In total, my recommended adjustments reduce the Company's

 3              requested revenue requirement increase by approximately $34.835 million.




     SECTION III. A.              FIN 48 TAX ADJUSTMENT

 4   Q:         HAVE YOU REVIEWED ETI'S PROPOSED FIN 48 ADJUSTMENT TO

 5              ACCUMULATED DEFERRED FEDERAL INCOME TAX ("AD FIT")?

 6   A:         Yes.    In June 2006, the Financial Accounting Standards Board issued Financial

 7              Interpretation 48, ("FIN 48"), Accounting for Uncertainty in Income Taxes, which

 8              requires companies with uncertain tax positions to remove these amounts from the

 9              ADFIT balance and record them as a separate liability, for financial accounting

10              purposes. FIN 48 became effective January 1, 2007.

11

12   Q:         HAS THE COMMISSION CONSIDERED THE RATEMAKING TREATMENT

13              OF THE FIN 48 PRONOUNCEMENT IN THE PAST?

14   A:         Yes. In Docket No. 35717, the Commission found that the subject utility, Oncor, should

15              include its FIN 48 amounts in ADFIT as a rate base deduction, stating: "Oncor may not

16              have to pay the IRS the FIN 48 deductions of $96,972,460; and therefore they should be

17              added back into the ADFIT for ratemaking purposes." 2 This ruling (1) reflects the fact

18              that the eventual treatment of these deductions is not currently known and (2) that in the


     2
         Order on Rehearing, Docket 35717, page 18 at 60.



     Direct Testimony of Mark E. Garrett                                                Page 5 of65
     Docket No. 39896
 1              meantime, the utility does have the use of the cost free capital             from the deferred taxes

 2              associated with these deductions         at its disposal.

 3

 4   Q:         IS THE COMPANY'S TREATMENT OF ITS FIN 48 ADJUSTMENTS

 5              CONSISTENT WITH THE COMMISSION'S RULING IN DOCKET NO. 35717?

 6   A:         No. The Company's FIN 48 adjustments remove $5,916,461 from ADFIT balance that

 7              should be included for ratemaking purposes. 3               In response to Cities RFI 19-6, the

 8              Company states:

 9                      "Because the Company removed all ADIT related to FIN48 uncertain tax
10                      positions from test year end ADIT balances, there would be no change to
11                      rate base. Please see the Company's response to Cities 4-21 (d) for the
12                      amounts removed from test year end ADIT."


13   Q:         SHOULD THE COMMISSION'S RULING IN DOCKET NO. 35717 APPLY IN

14              THIS CASE?

15   A:         Yes. The FIN 48 adjustments do reflect actual tax benefits from deductions taken by the

16              utility on its tax return, and the utility does have the use of these additional funds even if

17              the IRS were to reject the deductions, which may or may not ever happen.                            For

18              ratemaking purposes, rate base should reflect the actual amount of cost free capital in the

19              ADFIT accounts at test year end.




     3
         See AJ 10 for accounts 282901 and 282903 and the Highly Sensitive response to Cities 4-21.



     Direct Testimony of Mark E. Garrett                                                              Page 6 of65
     Docket No. 39896
 1   Q:      WHAT         IS    YOUR         RECOMMENDATION                   WITH        RESPECT           TO     THE

 2           COMP ANY'S FIN 48 ADJUSTMENT?

 3   A:      Consistent with the Commission's ruling in Docket No. 35717, I recommend that the

 4           Company's ADFIT balance be increased by $5,916,461 to reinstate the FIN 48 amounts

 5           removed by the Company. 4 This adjustment is set forth at Exhibit MG-2.1.



     SECTION III. B.            PREPAID PENSION ASSET IN RATE BASE

 6   Q:      PLEASE DESCRIBE THE COMPANY'S UNFUNDED PENSION BALANCE.

 7   A:      The Company included in pro forma rate base an item entitled Unfunded Pension

 8           Balance. The amount requested in this account is supposed to represent the accumulated

 9           difference between the Statement of Financial Accounting Standards ("SF AS") No. 87

10           calculated pension costs each year and the actual contributions made by the Company to

11           the pension fund. 5 The balance requested in rates is $55.9 million. 6

12

13   Q:      WHAT IS THE ISSUE WITH RESPECT TO A PENSION ASSET IN RATE

14           BASE?

15   A:      In general terms, a portion of the balance in Account 253.012, Unfunded Pension Plans

16           actually represents the accumulated difference between the SF AS 87 calculated pension

17           costs each year and actual contributions made by the Company to the pension fund.


     4
       This amount could be reduced by attributable IRS cash deposits identified by the Company in rebuttal testimony.
     5
       The Company incorrectly referred to this item as a PURA Section 36.065(b) reserve account. PURA Section
     36.065(b) allows a utility to record the difference between the SF AS No. 87 pension cost established in a rate case
     and the actual SFAS No. 87 cost experienced during the rate-effective period. The balance here is the difference in
     SF AS 87 costs and contributions.
     6
       See ETl response to Cities' 13-21.
     Direct Testimony of Mark E. Garrett                                                            Page 7 of 65
     Docket No. 39896
 1              When there is a debit balance in the account, as is the case here, the Company has been

 2              contributing more to the fund than its SF AS 87 calculated cost levels. 7

 3

 4   Q:         ARE THESE CONTRIBUTIONS MANDATORY?

 5   A:         No. Schedule G-2.1 shows the payments to the fund have significantly exceeded the

 6              required minimum contributions levels.

 7

 8   Q:         HAS THIS COMMISSION ADDRESSED THIS ISSUE IN A PREVIOUS CASE?

 9   A:         Yes. The Commission addressed this issue in an AEP Texas Central Company rate case,

10              PUC Docket No. 33309.         The Commission determined in that case that the excess

11              contributions to the pension fund, net of CWIP, resulted in lower future pension expense

12              levels for ratepayers. In effect, the Commission allowed the inclusion of a net pension

13              asset in rate base, because it provided a benefit to ratepayers.

14

15   Q:         DOES THE BENEFIT RECEIVED BY RATE PAYERS EQUAL THE INCREASE

16              IN RATES FROM INCLUDING EXCESS PENSION FUNDING IN RATE BASE?

17   A:         No. ETI's pension fund earns a much lower return on plan assets than ETI's requested

18              pretax return on rate base. The requested return on rate base is 11.5%, but the average

19              actual return on pension plan assets over the 5-year period since ETI became a separate

20              company, and the period over which substantially all of the prepaid pension buildup


     7
         See ETI response to Cities' 13-16.



     Direct Testimony of Mark E. Garrett                                                    Page 8 of65
     Docket No. 39896
 1            occurred, is only 1.37%. 8 Thus, if this asset were included in rate base, ratepayers would

 2            pay a substantial premium for the slight pension cost savings ETI' s excess contributions

 3            may have achieved. From a ratemaking perspective, it would be inappropriate for the

 4            Company to receive a greater benefit, through earning a full rate base return on the

 5            excess contributions, than the benefit ratepayers receive through lower pension costs that

 6            result from the pension fund returns. 9               In short, it would be inappropriate for the

 7            Company to earn an 11.5% return on contributions that have only produced a 1.37%

 8            benefit to ratepayers.

 9

10   Q:       HOW ARE PREPAID PENSION ASSETS TREATED IN OTHER STATES?

11   A:       At least one state, Virginia, has included a prepaid pension balance in rate base and

12            Texas has included a portion of a prepaid balance in rate base (which was the prepaid

13            pension balance less CWIP in the AEP TCC case). West Virginia, on the other hand, in

14            a recent decision, entirely excluded a requested prepaid pension balance. 10 In Oklahoma,

15            the commission addressed this issue in four separate decisions, and in each decision

16            excluded the prepaid pension balance from rate base and provided a cost of debt carrying

17            charge on the balance. 11 In effect, the Oklahoma commission provided a return on the

18            balance because ratepayers had received a benefit from the excess contributions in the


     8
       The annual returns for 2007 through 2011 are the actual returns divided by the average of the beginning and
     ending balance. The average of these amounts is 1.37%. See Exhibit MG2.2.
     9
       For example, in Oklahoma, the commission allows a cost-of-money return (rather than a full rate base return) on
     excess pension contributions ifthe utility can show that ratepayers benefited from the excess contributions. In
     those cases, the utility's long term debt rate was representative of, though lower than, the actual returns received in
     the pension fund.
     10
        See Commission Order on March 30, 2011 in Case No. 10-0699-E-42T.


     Direct Testimony of Mark E. Garrett                                                               Page 9 of65
     Docket No. 39896
 1           form of lower annual pension costs. In those cases, the actual pension fund returns were

 2           much more similar to a long-term debt return than to a full rate base return.

 3

 4   Q:      WHAT ADJUSTMENT ARE YOU PROPOSING?

 5   A:      I propose to remove the entire prepaid pension asset from rate base, because the

 6           Company has not justified its inclusion in any way. This adjustment reduces pro forma

 7           rate base by $36,382,803, which is the net amount of the prepaid balance less

 8           accumulated deferred income tax (55,973,543 - 19,590,740                  =   36,382,803)_12    I also

 9           recommend that the Commission increase operating expense by $498,284, to provide a

10           1.3 7% return on the net balance. The adjustment calculations are set forth at Exhibit

11           MG-2.2.

12                    In the alternative, if the Commission decides to follow its prior ruling in the AEP

13           TCC case, Docket No. 33309, the necessary reduction to pro forrna rate base would be

14           $25,311,236, which is the portion of the prepaid pension balance associated with

15           CWIP. 13




     11
        ONG rate case Cause No. PUD 91-1190; OG&E rate case Cause No. PUD 05-151; AEP PSO rate case Cause No.
     PUD 06-285; AEP PSO Cause No. PUD 08-144.
     12
        See ETI RFI response to Cities' 13-21.
     13
        The Company's expense ratio for pensions is 55.78% and the capitalization ratio is 44.22%. See ETI W/P AJ20.




     Direct Testimony of Mark E. Garrett                                                      Page 10 of65
     Docket No. 39896
     SECTION III. C.           RITA REGULATORY ASSET

 1   Q:      WHAT IS THE ISSUE WITH RESPECT TO THE RITA REGULATORY

 2           ASSET?

 3   A:      In this application the Company seeks to include a Rita Regulatory Asset in the amount

 4           of $26,229,627. 14 This balance represents the unrecovered insurance proceeds from the

 5           Rita storm loss. The Company seeks rate base treatment of the regulatory asset balance

 6           along with a 5-year amortization of the balance in rates.                    The problem with the

 7           Company's recommended treatment in this case is that the Rita balance was presented in

 8           the Company's last rate case, Docket No. 37744, as a regulatory asset with a 5-year

 9           amortization of the balance and no party in that case opposed the recovery of those costs

10           through rates. This means that, even though the last rate case settled, since no party

11           opposed the Company's inclusion in rates of the Rita regulatory costs, the Company

12           should have been amortizing the Rita regulatory balance since the last case, which would

13           mean that 22.5 months of the 60 month amortization would be complete by the time new

14           rates go into effect from this case. 15 From a ratemaking perspective, the appropriate

15           balance for rate treatment at this point would be $10,714,557, 16 which is the original

16           balance of $26,229,627, less $9,836,110, 22.5 months of the 5-year amortization, less

17           $5,678,960, which is the difference between insurance proceeds estimated in Docket No.

18           37744 and actual receipts. These calculations are set forth at MG-2.3

     14
        See Sch. P, P. 19, L. 23.
     15
        New rates from Docket No. 37744 went into effect on August 15, 2010 and new rates from this case will go into
     effect on June 30, 2012.
     16
        This is the balance that Mr. Pous will include in the storm reserve.



     Direct Testimony of Mark E. Garrett                                                        Page 11 of65
     Docket No. 39896
 1   Q:      WHAT DOES CITIES RECOMMEND WITH RESPECT TO THE RITA

 2           REGULATORY ASSET?

 3   A:      The recommended rate treatment of the Rita regulatory asset going forward is being

 4           addressed in the testimony of Cities' witness, Mr. Jacob Pous, who recommends that the

 5           Rita regulatory asset balance be added to and amortized in the storm reserve. In light of

 6           this alternate recovery methodology for the Rita regulatory asset balance I am

 7           recommending that the entire balance be removed from pro forma rate base and the

 8           amortization expense be removed from pro forma cost of service.        This results in a

 9           reduction to the requested rate base of $26,229,627 and a reduction to the requested cost

10           of service of$5,245,925. These adjustments are set forth at Exhibit MG 2.3.



     SECTION IV. A.          ETI PAYROLL ADJUSTMENT

11   Q:      PLEASE DESCRIBE ETI'S PROPOSED PAYROLL ADJUSTMENT.

12   A:      ETI's payroll adjustment contains three components: (1) a decrease of $648,362 for a

13           reduction in the number of ETI employees during the test year, estimated by multiplying

14           the effective number of employees who left the Company by an average annual salary

15           amount; (2) an increase of $350,047 to recognize test year pay raises for both bargaining

16           and non-bargaining employees; 17 and (3) an increase of $628,947 for post-test year pay

17           raises for both bargaining and non-bargaining employees, calculated by multiplying total

18           payroll expense by the nominal rate of the pay raise.      The post-test year raises for

19           bargaining employees occurred in early August 2011, just over one month after test year



     Direct Testimony of Mark E. Garrett                                           Page 12 of65
     Docket No. 39896
 1           end. The post-test year raises for non-bargaining employees are scheduled to occur in

 2           April 2012, nine months after test year end. The combination of these three adjustments

 3           results in a net requested increase to ETI payroll expense of $330,632. 18

 4

 5   Q:      DO YOU AGREE WITH THE COMP ANY'S PROPOSED ADJUSTMENT TO

 6           ETI PAYROLL EXPENSE?

 7   A:      I agree with the first two components of the Company's proposed adjustment, where the

 8           Company attempts to reflect workforce reductions and pay raises that occur during the

 9           test year.    And, in the third component, I agree with the post-test year raises for

10           bargaining employees that occurred shortly after test year end. However, I do not agree

11           with the Company's adjustment which attempts to reflect the effects of pay raises that

12           are expected to occur up to nine months after test year end.                  From a ratemaking

13           perspective, there are several problems with the Company's proposed recognition of

14           these post-test year raises.

15

16   Q:      WHAT         ARE    THE       PROBLEMS         YOU      SEE     WITH       THE     COMP ANY'S

17           PROPOSED APPROACH?

18   A:      First, the Company's method of calculating the impact of the pay raise is based on the

19           flawed assumption that a pay raise that occurs nine months after test year end would

20           increase test year payroll expense by the same amount as the pay raise. This assumption,


     17
        The Company awarded bargaining employees an effective 0.72% pay raise on 3/20/11 and non-bargaining
     employees an effective 1.50% pay raise on 4/1/11.
     18
        See Workpaper AJ22.12.

     Direct Testimony of Mark E. Garrett                                                    Page 13 of65
     Docket No. 39896
            however, fails to consider other events occurring during the same period that could

 2          decrease payroll levels by the same, or even greater, amounts. For example, workforce

 3          reductions could have a greater impact on payroll expense than pay raises. In addition,

 4           other more subtle changes may also decrease payroll levels. Even with a stable overall

 5          workforce level, employees are being added to and removed from the payroll registers

 6           on a fairly regular basis. Since retiring employees are generally paid higher salaries than

 7          new employees, payroll expense levels can decrease significantly if higher paid

 8           employees leave the company and are replaced with employees paid at lower

 9           compensation levels. These potential reductions in payroll expense can more than offset

10          the anticipated increase from an annual raise.          As a consequence, even if the

11           Commission were inclined to accept an adjustment for pay raises that occur up to nine

12          months outside the test year, the Company's proposed adjustment is inappropriate

13          because it fails to show that net payroll expense levels actually increased by the amount

14           of the pay raises.

15

16   Q:      IF THE COMMISSION WERE INCLINED TO ACCEPT AN INCREASE FOR

17           PAY RAISES THAT OCCUR UP TO NINE MONTHS OUTSIDE THE TEST

18           YEAR, HOW WOULD THE IMP ACT OF THESE RAISES BE PROPERLY

19           MEASURED FOR RATEMAKING PURPOSES?

20   A:      In my experience, payroll levels generally do not increase by the nominal amount of a

21           pay raise. In other words, a 3.5% pay raise typically does not result in a 3.5% increase in

22           overall payroll costs. To calculate the effective impact of a pay raise, it is necessary to

     Direct Testimony of Mark E. Garrett                                            Page 14 of65
     Docket No. 39896
 1           annualize the Company's actual payroll cost levels after the raise was awarded. This

 2           approach takes the guess-work out of estimating the impact of a pay raise.            The

 3           Company's approach of merely taking the amount of the nominal pay raise increase and

 4           applying it to overall payroll expense is not an accurate method for estimating the impact

 5           of a pay raise and should not be used for ratemaking purposes. In this case, it would be

 6           necessary to annualize the April 2012 payroll levels in order to effectively realize the

 7           April 2012 pay raise for non-bargaining employees.

 8

 9   Q:      EVEN IF THE AD.JUSTMENT WAS APPROPRJATEL Y BASED ON A PROPER

10           ANNUALIZATION OF PAYROLL LEVELS AT APRIL 2012, WOULD THE

11           RECOGNITION OF THESE POST TEST YEAR RAISES BE APPROPRIATE

12           FROM A RATEMAKING PERSPECTIVE?

13   A:      No.   From a ratemaking perspective, it is generally considered inappropriate to go

14           beyond the test year to recognize an isolated increase in one expense item, such as

15           payroll, without also recognizing other potential offsetting decreases, such as higher

16           revenue levels from load growth.    The Company's proposed isolated recognition of pay

17           raises that occur nine months after test year end, without offsetting adjustments, amounts

18           to a piecemeal ratemaking approach for payroll costs and, in my opinion, should be

19           rejected by this Commission. The Company makes no attempt to update its Revenue, or

20           Accumulated Depreciation, or Accumulated Deferred Income Tax balances to a nine-

21           month post-test year level, each of which would more than offset the proposed increase

22           from the April 2012 raises. In my opinion, it is inappropriate to recognize an increase in

     Direct Testimony of Mark E. Garrett                                            Page 15 of65
     Docket No. 39896
 1              one item nme months after test year end, while ignoring other obvious decreases.

 2              Jurisdictions with which I am familiar typically require that if one item is updated to a

 3              point in time substantially after test year end, then all items must be updated to that later

 4              date as well. An isolated increase in one expense item is not allowed.

 5

 6   Q:         ARE THERE OTHER REASONS WHY THE COMMISSION SHOULD NOT

 7              INCLUDE THE APRIL 2012 PAY RAISES IN RATES?

 8   A:         Yes. According to Mr. Gardner's testimony, the Company's total payroll costs for 2011,

 9              including both base pay and incentives, was I 0% above market. 19 Most of these above-

10              market payroll costs relate to the Company's incentives.        The Company's incentive

11              levels are 63% above-market and the Company's base pay levels are 2% above market,

12              resulting in total above-market level of 10% for base pay and incentives. 20 The above-

13              market incentive pay is addressed in detail later in this testimony.          However, the

14              Company's above-market base pay is relevant to mention here as well. Because the

15              Company's 2011 base pay is already 2% above market, an additional 2% pay raise

16              increase in April 2012 will only further exacerbate the problem.




     19
          See Table 5 at page 26 of Mr. Gardner's Direct Testimony.
     20
          See ETI response to Cities' RFI 18-S(b ).




     Direct Testimony of Mark E. Garrett                                                 Page 16 of65
     Docket No. 39896
 l   Q:      IF THE COMMISSION FINDS IT APPROPRIATE TO RECOGNIZE THE

 2           COMP ANY'S POST TEST YEAR PAY RAISES IN APRIL 2012, WHAT OTHER

 3           ADJUSTMENTS SHOULD THE COMMISSION ALSO RECOGNIZE?

 4   A:     If the Commission decides to recognize the April 2012 post-test year pay raises, I believe

 5           the Commission should, at a minimum, consider offsetting the post-test year pay raise

 6           increases with the overall productivity improvements that should occur over the same

 7           period of time. These productivity improvements must be considered in forward-looking

 8           adjustments to payroll costs, such as the Company's proposed pay raise increases. It

 9           would be inappropriate for the Company to recognize the incremental increases to

10           payroll associated with post-test year pay raises payroll and not consider the mitigating

11           effects of increased productivity.

12

13   Q:     WHAT IS PRODUCTIVITY GROWTH AND WHY IS IT IMPORTANT IN THIS

14           CASE?

15   A:      In economic terms, increased productivity is the ability to produce more with less input.

16           Productivity is measured by comparing the amount of goods and service produced with

17           the inputs used in the production of a product. Specifically, labor productivity is the

18           ratio of the output of goods and service to the labor hours devoted to the production of

19           the output. The Bureau of Labor Statistics ("BLS") reports significant growth in labor

20           productivity over the past few years.




     Direct Testimony of Mark E. Garrett                                           Page 17 of 65
     Docket No. 39896
 1   Q:      WHY IS IT IMPORTANT TO RECOGNIZE PRODUCTIVITY GROWTH IN

 2           THIS SITUATION?

 3   A:      Labor productivity is important here because of the forward-looking impacts of the post-

 4           test year pay raises. An accurate projection of post-test year labor costs must give some

 5           recognition to the expectation of increased productivity.

 6

 7   Q:      WHAT AMOUNT OF PRODUCTIVITY GROWTH COULD BE EXPECTED

 8           FOR THE COMPANY?

 9   A:      Based on projected productivity growth statistics, a reasonable productivity adjustment

10           would reduce labor cost by about 2.1 %.           The BLS reported "business sector"

11           productivity growth of .4% for 2011, 4% for 2010, and 2.3% for 2009. This results in a

12           3-year average productivity growth of about 2.2%. The past 2-year average is 2.1 %. A

13           productivity offset of 2.1 % would recognize the fact that the Company should be

14           expected to achieve the same type of productivity gains that the business sector achieves

15           on average.

16

17   Q:      HOW       WOULD         A     PRODUCTIVITY         ADJUSTMENT         IMP ACT        THE

18           COMP ANY'S PROPOSED INCREASE FOR APRIL 2012 P AYRAISES?

19   A:      The Company's projected labor cost increases of 2% would be more than offset with a

20           2.1 % annual productivity factor.




     Direct Testimony of Mark E. Garrett                                           Page 18 of65
     Docket No. 39896
 1   Q:      WHAT       IS    YOUR         RECOMMENDATION             WITH   RESPECT    TO      THE

 2           COMPANY'S PAYROLL EXPENSE?

 3   A:      I recommend the Commission: (1) accept the Company's adjustment to decrease payroll

 4           expense for workforce reductions in the test year; (2) accept the Company's adjustment

 5           to increase payroll expense for pay raises awarded in March and April 2011 for

 6           bargaining and non-bargaining employees respectively; (3) accept the Company's

 7           adjustment to increase payroll for pay raises awarded in August 2011 for bargaining

 8           employees; and (4) reject the Company's adjustment to increase payroll expense for pay

 9           raises awarded in April 2012 for non-bargaining employees.

10

11   Q:      PLEASE DESCRIBE YOUR PROPOSED ADJUSTMENT TO PAYROLL

12           EXPENSE.

13   A:      My recommended adjustment reverses the Company's proposed increase for April 2012

14          pay raises in the amount of $316,989 and associated payroll-related expense of $41,081,

15           for a total adjustment of $358,071. The calculations supporting Cities' recommended

16           ETI payroll adjustment is set forth at Exhibit MG-2.4.



     SECTION IV. B.          ESI PAYROLL ADJUSTMENT

17   Q:      HAVE YOU REVIEWED THE COMP ANY'S PROPOSED ADJUSTMENT FOR

18           ESI PAYROLL EXPENSE?

19   A:      Yes.   Like the ETI payroll adjustment, the ESI payroll adjustment contains three

20           components: (1) a decrease of $243 ,416 for a reduction in the number of ESI employees

     Direct Testimony of Mark E. Garrett                                         Page 19 of65
     Docket No. 39896
 1           during the test year, estimated by multiplying the effective number of employees who

 2           left the Company by an average annual salary amount; (2) an increase of $466,666 to

 3           recognize test year pay raises for non-bargaining employees; 21 and (3) an increase of

 4           $622,221 for post-test year pay raises for non-bargaining employees, calculated by

 5           multiplying total payroll expense by the nominal rate of the pay raise. The post-test year

 6           pay raises for ESI employees are scheduled to occur in April, nine months after test year

 7           end. The combination of all three of these adjustments results in a net requested increase
                                                                        22
 8           in ESI payroll expense allocated to ETI of $845,471.

 9

10   Q:      DO YOU AGREE WITH THE ESI PAYROLL ADJUSTMENT?

11   A:      Not entirely. I agree with the first two components of the adjustment that occur during

12           the test year-the test year workforce reductions and the test year pay raises-but I do

13           not agree with the third component of the adjustment that inappropriately increases

14           payroll expense for pay raises expected to occur nine months after test year end.               Not

15           only does this proposed adjustment fall far outside the test year, it also improperly

16           calculates the impact of these raises by merely multiplying labor costs times the nominal

17           percentage of the raise.




     21
        The Company awarded bargaining employees an effective .72% pay raise on 3/20/11 and non-bargaining
     employees an effective 1.50% pay raise on 4/1/11.
     22
        See Workpaper AJ22.23.




     Direct Testimony of Mark E. Garrett                                                    Page 20 of65
     Docket No. 39896
 1   Q:         EVEN IF THE ADJUSTMENT WAS APPROPRIATELY BASED ON A PROPER

 2              ANNUALIZATION OF PAYROLL LEVELS AT APRIL 2012, WOULD THE

 3              RECOGNITION OF THESE POST TEST YEAR RAISES BE APPROPRIATE

 4              FROM A RA TEMAKING PERSPECTIVE?

 5   A:         No. From a ratemaking perspective, it is inappropriate to go beyond the test year to

 6              recognize an isolated increase in one expense item, such as payroll, without also

 7              recognizing other potential offsetting decreases, such as higher revenue levels from load

 8              growth. As I testified with respect to the Company's proposed ETI Payroll adjustment,

 9              the proposed adjustments to ESI payroll expense also recognize pay raises that occur

10              nine months after test year end without offsetting adjustments.             This amounts to

11              piecemeal ratemaking for payroll costs and should be rejected by this Commission.

12              Because the Company makes no attempt to update Revenue, or Accumulated

13              Depreciation or Accumulated Deferred Income Tax balances to the nine-month post-test

14              year level, it is inappropriate to recognize an increase in a single isolated item.

15

16   Q:         ARE THERE OTHER REASONS WHY THE COMMISSION SHOULD NOT

17              INCLUDE THE APRIL 2012 PAY RAISES IN RATES?

18   A:         Yes. As discussed in the previous section of this testimony, Mr. Gardner's testimony

19              and responses to Cities' RFis indicate that the Company's 2011 base pay levels are 2%

20              above market. 23 With the Company's 2011 base pay levels already 2% above-market, an


     23
          See ETI response to Cities' RFI l 8-8(b ).



     Direct Testimony of Mark E. Garrett                                                  Page 21 of65
     Docket No. 39896
 1           additional 2% increase for pay raises in April 2012 would only further exacerbate the

 2           problem.

 3

 4   Q:     IF THE COMMISSION FINDS IT APPROPRIATE TO RECOGNIZE THE

 5           COMPANY'S POST TEST YEAR PAY RAISES, IN APRIL 2012, WHAT

 6           OTHER ADJUSTMENTS SHOULD THE COMMISSION ALSO RECOGNIZE?

 7   A:     If the Commission should decide to recognize the April 2012 post-test year pay raises, I

 8           believe the Commission should offset the 2% pay raises with a 2.1 % productivity

 9          adjustment, which, according to the BLS, is the two-year average productivity factor for

10          the business sector.

11

12   Q:     WHAT        IS    YOUR         RECOMMENDATION        WITH     RESPECT       TO      THE

13           COMPANY'S PAYROLL EXPENSE?

14   A:     I recommend the Commission: (1) accept the Company's adjustment to decrease payroll

15          expense for workforce reductions in the test year; (2) accept the Company's adjustment

16          to increase payroll expense for pay raises awarded in April 2011 (during the test year);

17           and (3) reject the Company's adjustment to increase payroll expense for post-test year

18           pay raises awarded in April 2012.

19

20   Q:      PLEASE DESCRIBE YOUR PROPOSED ADJUSTMENT TO PAYROLL

21           EXPENSE.

22   A:      My recommended adjustment reverses the Company's proposed increase for April 2012

     Direct Testimony of Mark E. Garrett                                         Page 22 of65
     Docket No. 39896
 1             pay raises in the amount of $622,220, and associated payroll-related expense in the

 2             amount of $80,640, for a total adjustment of $702,861. The calculations supporting

 3              Cities' recommended ESI payroll adjustment is set forth at Exhibit MG-2.7.



     SECTION IV. C.             SABINE AND LEWIS CREEK PAYROLL ADJUSTMENT

 4   Q:        HAVE YOU REVIEWED THE COMP ANY'S PROPOSED ADJUSTMENTS FOR

 5              SABINE AND LEWIS CREEK PAYROLL EXPENSE?

 6   A:         Yes. Like the ETI and ESI payroll adjustment, the Sabine and Lewis Creek payroll

 7             adjustment contains three components: (1) an increase for employees added during the

 8             test year; (2) an increase to recognize test year pay raises for both bargaining and non-

 9             bargaining employees; and (3) an increase for post-test year pay raises for both

10             bargaining and non-bargaining employees, calculated by multiplying total payroll

11             expense by the nominal rate of the pay raise. The post-test year raises for bargaining

12              employees occurred in early August 2011, just over one month after test year end. The

13             post-test year raises for non-bargaining employees are scheduled to occur in April 2012,
                                                  24
14             nine months after test year end.

15

16   Q:         DO YOU AGREE WITH THE COMP ANY'S PROPOSED SABINE AND LEWIS

17              CREEK PAYROLL ADJUSTMENTS?

18   A:         No. As with the ETI and ESI adjustments, I agree with the first two components of the

19              Company's proposed adjustment, where the Company attempts to reflect workforce


     24
          See Workpapers AJ22.15 and AJ22.18.
     Direct Testimony of Mark E. Garrett                                             Page 23 of65
     Docket No. 39896
 1           additions and pay raises that occur during the test year. And, I also agree with the post-

 2           test year raises for bargaining employees that occurred shortly after test year end.

 3           However, I do not agree with the component of the Company's adjustment that attempts

 4           to reflect the effects of pay raises that are expected to occur up to nine months after test

 5           year end. From a ratemaking perspective it is inappropriate to go that far beyond the test

 6           year to recognize an isolated increase in one expense item without also recognizing

 7           offsetting decreases in other items, such as revenue, accumulated depreciation and

 8           accumulated deferred income taxes. Also, pay raises projected that far beyond the test

 9           year should be offset with an appropriate corresponding productivity adjustment.

10

11   Q:      WHAT       IS    YOUR         RECOMMENDATION           WITH      RESPECT        TO     THE

12           COMPANY'S PAYROLL EXPENSE?

13   A:      I recommend the Commission: (1) accept the Company's adjustment to increase payroll

14           expense for workforce additions in the test year; (2) accept the Company's adjustment to

15           increase payroll expense for pay raises awarded in April 2011 (during the test year) and

16           in August 2011 shortly after test year end; and (3) reject the Company's adjustment to

17           increase payroll expense for post-test year pay raises awarded in April 2012, nine

18           months after test year end.

19

20   Q:      PLEASE DESCRIBE YOUR PROPOSED ADJUSTMENT TO PAYROLL

21           EXPENSE.

22   A:      For Sabine, my recommended adjustment reverses the Company's proposed increase for

     Direct Testimony of Mark E. Garrett                                             Page 24 of65
     Docket No. 39896
 l              April 2012 pay raises in the amount of $81,894 and associated payroll-related expense in

 2              the amount of $10,613, for a total adjustment of $92,507.          For Lewis Creek, my

 3              recommended adjustment reverses the Company's proposed increase for April 2012 pay

 4              raises in the amount of $28,659 and associated payroll-related expense in the amount of

 5              $3,713, for a total adjustment of $32,372.            The calculations supporting Cities'

 6              recommended Sabine and Lewis Creek payroll adjustments are set forth at Exhibit MG-

 7              2.5 and MG 2.6.




     SECTION IV. D.               ABOVE-MARKET BASE PAY COMPENSATION

 8   Q:         WHAT IS THE ISSUE REGARDING THE COMPANY'S ABOVE-MARKET

 9              BASE PAY LEVELS?

10   A:         According to Mr. Gardner's testimony, the Company's total payroll costs for 2011,

11              including both base pay and incentives, is 10% above market. 25 Most of these above-

12              market payroll costs relate to the Company's incentives.        The Company's incentive

13              levels are 63% above-market, and the Company's base pay levels are 2% above market,

14              resulting in total above-market level of 10% for both components. 26 The Company's

15              incentive compensation is addressed in another section of this testimony. In this section,

16              I address the Company's above-market base pay compensation.




     25
          See Table 5 at page 26 of Mr. Gardner's Direct Testimony.
     Direct Testimony of Mark E. Garrett                                               Page 25 of65
     Docket No. 39896
 1    Q:         ARE YOU PROPOSING AN ADJUSTMENT TO THE BASE PAY LEVEL

 2               REQUESTED IN RATES?
 ,,
 .)   A:         Yes. From a ratemaking perspective, ratepayers are only required to pay the necessary

 4               costs of providing utility service. Although the Company is certainly free to pay its

 5               employees at above-market wage levels if it so chooses, ratepayers should only be asked

 6               to pay market-based costs for utility services the Company provides. Based upon the

 7               Company's own calculation, its base pay wage levels are above market.                  This is

 8               particularly inappropriate when ratepayers are experiencing, arguably, the worst

 9               economy in the past 30 to 35 years           and quite possibly the worst economy since the

10               great depression.        In light of this economic downturn, it would be particularly unfair to

11               ask captive ratepayers to pay above-market wages for utility services. As a result, I am

12               recommending a 2% adjustment to the payroll expense included in pro forma rates, to

13               bring the Company's base pay down to a market-based level.

14

15    Q:         IF THE COMMISSION ADOPTS YOUR ADJUSTMENT, WILL IT RESULT IN

16               A 2% PAYROLL REDUCTION?

17    A:         No, certainly not. The Company alone decides how much it pays its employees; the

18               Commission, on the other hand, decides how much of that cost should be collected from

19               ratepayers. The Company will continue to pay its employees whatever it believes is

20               appropriate. Ratepayers, however, should bear only the necessary market-based price

21               for employee pay.


      26
           See ETI response to Cities' RFI l 8-8(b ).
      Direct Testimony of Mark E. Garrett                                                    Page 26 of65
      Docket No. 39896
     Q:      HOW IS YOUR PROPOSED ADJUSTMENT CALCULATED?

 2   A:      The adjustment is calculated by multiplying base pay wages in operating expense by

 3           2%. 27 This results in an adjustment of $989,370, 28 which can be seen at Exhibit MG2.8.



     SECTION IV. E.            ETI INCENTIVE COMPENSATION

 4   Q:      HAVE YOU REVIEWED THE LEVEL OF INCENTIVE COMPENSATION

 5           EXPENSE INCLUDED IN THE COMPANY'S COST OF SERVICE?

 6   A:      Yes.    The Company seeks to include $14, 187, 744 in cost of service for incentive

 7           compensation expense.          This includes 100% of ETI and ESI annual incentive plan

 8           compensation, 100% of ETI and ESI long-term incentive compensation, and 100% of

 9           ETI and ESI equity ownership incentive compensation.                     The Company makes no

10           adjustment to remove any of its test year incentive expense from cost of service, even

11           though it admits that at least 35% of the annual incentive plans and 100% of the long-

12           term plans are tied to the type of financial performance measures that the Commission

13           has routinely excluded in the past. 29 The Company's proposed inclusion of financial-

14           based incentive compensation is supported in the testimony of Jay C. Hartzell, who

15           asserts that incentive programs tied to cost controls, profitability and stock price help

16           companies attract, motivate and retain talented employees. The Company asserts that

17           without financial-based incentives, employees would not be motivated to look after the

     27
        The actual percentage is 1.8%. See, ETI response to Cities' RFI l 8-8(b ).
     28
        Base pay payroll expense for ETI and ESI = $54.965 million times 1.8%. = $989,370. (See, TIEC 9-1 and Cities'
     l 8-8(b)).
     29
        Please see Testimony of Jay C. Hartzell, PhD at page 9 for the admission, and Gardner Exhibit KGG-4 for the
     percentage.

     Direct Testimony of Mark E. Garrett                                                       Page 27 of65
     Docket No. 39896
 1              financial health of the company. 30 The inclusion of financial-based incentives is also

2               supported in the testimony of Kevin G. Gardner, who asserts that the incentives are part

 3              of a total package of compensation and benefits that is reasonable when compared with

4               other companies. 31 ETI's test year incentive expense levels and the amounts included in

 5              cost of service are set forth in the table below:




                        Table 1: Total Incentive Compensation Expense in Cost of Service

                                                                                              Amount Included in
                    Incentive Compensation Programs                   I   Test Year Expense
                                                                                               Cost of Service
                 Management Incentive Plan                                       $4,749,198           $4,749,198
                 Exempt Incentive Plan                                           $1,858,337           $1,858,337
                 Team Share Incentive Plan                                         $153,447             $153,447
                 Team Share for Bargaining Employees                               $384,877             $384,877
                 Executive Annual Incentive Plan                                 $1,483,447           $1,483,447
                 ML6 Operational Plan                                               181,462              181,462
                 Long-Term Incentive Plans                                         $815,608             $815,608
                 Equity Ownership Plans                                          $4,561,367           $4,561,367

                 Total Incentive Compensation                                   $14,187,744          $14,187,744



6    Q.         WHAT         IS    YOUR        RECOMMENDATION                   WITH     RESPECT      TO      THE

7               COMPANY'S INCENTIVE COMPENSATION EXPENSE?

 8   A.         For incentive compensation expense, the general rule followed in most states is that

9               incentive payments related to the financial performance of the company are excluded for

10              ratemaking purposes. Under this rule, most short-term incentive expense and virtually


     30
          Direct Testimony of Jay C. Hartzell, PhD at page 7, lines 9-17.
     31
          Direct Testimony of Kevin G. Gardner at pages 5-30.



     Direct Testimony of Mark E. Garrett                                                       Page 28 of65
     Docket No. 39896
 1            all long-term incentive expense for executives is excluded.                    In my opinion, this rule

 2            should be applied to ETI's incentive plans.

 3

 4   Q:       WHAT IS THE GENERAL RATIONALE FOR EXCLUDING INCENTIVE

 5            COMPENSATION TIED TO FINANCIAL PERFORMANCE?

 6   A:       When incentive compensation costs associated with financial performance are excluded

 7            from rates, the rationale is generally based on one or more of the following reasons:

 8            (1)      Payment is uncertain. Often, payment of incentive compensation is conditioned
 9                     upon meeting some predetermined financial goal such as achieving a certain
10                     increase in earnings, reaching a targeted stock price or meeting budget objectives.
11                     If the predetermined goals are not met, the incentive payment is not made, or
12                     payment is made at some lesser amount. Therefore, there is no certainty from
13                     year to year what the level of the payment may be or whether the payment will be
14                     made at all. It is generally considered inappropriate to set rates to recover a
15                     tentative level of expense 32

16            (2)      Many of the factors that significantly impact earnings are outside the control
17                     of most company employees and have limited value to customers. For
18                     example, an unusually hot summer can easily trigger an incentive payment based
19                     on company earnings for an electric utility. Obviously, weather conditions are
20                     outside the control of utility employees and customers receive no benefit from
21                     the higher utility bills that result from an unusually hot summer. Similarly,
22                     company earnings may increase, thus triggering incentive payments, as a result of
23                     customer growth, which commonly occurs without significant influence from
24                     company personnel. In fairness, since shareholders enjoy the benefits of
25                     customer growth between rate cases, shareholders should also bear the cost of
26                     any incentive payments such growth may trigger. Finally, utility earnings may
27                     increase substantially if the utility is able to successfully argue for a higher ROE
28                     in a rate case proceeding. However, utility efforts to maximize ROE in a rate
29                     proceeding have little to do with improving overall employee performance across
30                     the company. If utility employee efforts are geared toward securing an
     32
        This general rationale for excluding financial-based incentives is on point in this case. At page 28, lines 8-14, of
     his Direct Testimony, Mr. Gardner admits that actual payments for financial incentives may be considerably less
     than the targeted level. For example, the actual payouts under the Performance Unit Programs were only 57% of
     the targeted level in 2010 and a mere 10% of the target level in 2011.



     Direct Testimony of Mark E. Garrett                                                             Page 29 of65
     Docket No. 39896
 1                    unreasonably high ROE in a rate proceeding, the incentive mechanism actually
 2                    would work to the detriment of the utility customers.

 3           (3)      Earnings-based incentive plans can discourage conservation. When incentive
 4                    payments are based on earnings, employees may not be as supportive of
 5                    conservation programs designed to reduce usage if they perceive these programs
 6                    could adversely impact incentive payment levels. To the extent earnings-based
 7                    incentive plans discourage conservation and demand-side management programs,
 8                    these plans would not be in the public interest. This point is especially important
 9                    in light of the growing focus on energy efficiency at both the national and state
10                    level. 33

11           (4)      The utility and its stockholders assume none of the financial risks associated
12                    with incentive payments. Ratepayers assume the risk that the amounts collected
13                    through rates for incentive payments will instead be retained by the utility
14                    whenever targeted increases are not reached. Employees assume the risk that the
15                    incentive payments will not be made in a given year. However, the utility and its
16                    stockholders assume no risk associated with these payments. Instead, the
17                    company's only responsibility is to decide who gets the money, the stockholders
18                    or the employees.

19           (5)      Incentive payments based on financial performance measures should be
20                    made out of increased earnings. Whatever the targets or goals may be that
21                    trigger an incentive payment, when the plan is based in whole or in part on
22                    financial performance measures there is always a financial benefit to the
23                    company that comes from achieving these objectives. This financial benefit
24                    should provide ample funds from which to make the payment. If not, the
25                    incentive plan was poorly conceived in the first place. As such, employees
26                    should be compensated out of the increased earnings, and not through rates.

27           (6)      Incentive payments embedded in rates shelter the utility against the risk of
28                    earnings erosion through attrition. When utilities are allowed to embed
29                    amounts for incentive payments in rates that money is available to the utility not
30                    only to pay the incentive payment when financial performance goals are met but
31                    also to supplement earnings in those years when the company does not perform
32                    well. In those years when financial performance measures are met, the increased
33                    earnings of the company provide ample additional funds from which to make the
34                    incentive payments to employees, and the incentive payment amount embedded
35                    in rates is not needed. In those years when financial performance measures are
36                    not met and the incentive payments are not made, the amount embedded in rates
     33
       This general rationale for excluding financial-based incentives is particularly important in Texas, since the
     Commission's rules specifically disallow expenses that would promote increased consumption of electricity. See
     §25 .231 (b )(2)(F).

     Direct Testimony of Mark E. Garrett                                                        Page 30 of65
     Docket No. 39896
 1                   for incentive payments acts as a financial hedge to shelter the poor financial
 2                   performance of the company.


 3           Even though regulators often exclude incentive compensation payments based on one or

 4           more of the reasons outlined above, this does not mean that regulated companies should

 5           not offer incentive compensation packages.           To the contrary, incentive plans that

 6           motivate employees to achieve increased efficiencies (i.e., cost control) should be

 7           encouraged.      However, since the utility retains the savings generated from these

 8           increased efficiencies between rate cases, payment to the employees for these plans

 9           should be made from a portion of the savings these plans help achieve. Thus, incentive

10           compensation plans designed to enhance financial performance need not be subsidized

11           by ratepayers.

12

13   Q.      HOW IS INCENTIVE COMPENSATION TREATED FOR RATEMAKING

14           PURPOSES IN TEXAS?

15   A.      My understanding is that the Commission generally excludes the portion of incentive

16           payments designed to increase the financial position of the utility. For example, in PUC

17           Docket No. 28840, 34 the Commission disallowed sixty-six percent (66%) of AEP-Texas

18           Central's test year incentive payments in the amount of $4.2 million -- the portion of the

19           utility's incentive payments that was based on financial performance measures. 35




     34
      Application ofAEP Texas Central Company for Authority to Change Rates, Docket No. 28840; SOAH Docket
     No. XXX-XX-XXXX, Final Order(August 15, 2005).


     Direct Testimony of Mark E. Garrett                                                Page 31of65
     Docket No. 39896
 1   Q:      HOW IS INCENTIVE COMPENSATION TREATED IN OTHER STATES?

 2   A:      The results of an Incentive Survey of 24 Western States 36 taken by the Garrett Group in

 3           2007, and updated in 2009 and again in 2011, show that most states follow guidelines

 4           similar to those described above for Texas, where incentive pay associated with financial

 5           performance is not allowed in rates. Some states disallow incentive pay using other

 6           criteria.    None of the jurisdictions surveyed allow full recovery of incentive

 7           compensation through rates as a general rule.            The results of the survey are set forth

 8           below.


     States that closely follow the Financial Performance rule

 9           Arizona          The commission deals with incentive compensation plans on a case by
10                            case basis. It first compares overall compensation to the state norm, then
11                            asks if the costs are prudent and reasonable. The commission leans
12                            toward disallowing programs which benefit only the shareholder even if
13                            total compensation is comparable to the state norm. Staffs position is that
14                            unless a plan is tied to performance issues it is unnecessary for the
15                            provision of service and that shareholders should pay for plans tied to
16                            financial measures. In practice, the costs of annual incentive plans are
17                            often shared 50/50 between ratepayers and shareholders. 37

18           Arkansas         Excludes 100% of the long-term, equity-based plans.           Short-term
19                            incentive plans are evaluated to determine if they are based on financial
20                            or operational measures. Operational-based plans are allowed. 50% of
21                            plans containing financial measures are disallowed. Any plans based
22                            solely on the discretion of the company are seen as having no direct
23                            benefit to ratepayers and are disallowed 100%. Settlements in recent
24                            cases have upheld this treatment. 38


     35
        See ALJ's Proposal for Decision at page 113 in PUC Docket No. 28840, SOAH Docket No. XXX-XX-XXXX, issued
     July I, 2004. The PFD with respect to the treatment of incentive compensation was adopted by the Commission in
     its Final Order.
     36
        The survey does not cover Nebraska because the state does not regulate investor-owned electric utilities.
     37
        See e.g., APS 2008 rate case, Decision 70360, Southwest Gas 2008 rate case, Decision 70665 and UNS Gas 2008
     rate case, Decision 70011.
     38
        Entergy Arkansas, 06-101-U, Order No. 10.
     Direct Testimony of Mark E. Garrett                                                      Page 32 of65
     Docket No. 39896
 1           California        Incentive funding is an issue that is typically litigated. In CPUC Decision
 2                             00-02-046, the commission established that utilities could recover 50% of
 3                             the regular employee's incentive compensation costs in rates. In
 4                             California's latest litigated rate case, the commission decided that
 5                             Edison's non-executive plans and 50% of the short-term executive plans
 6                             would be funded in rates and that 100% of the executive long-term stock
 7                             plans would be disallowed. 39

 8           Colorado          Regular employee programs are judged based on ratepayer verses
 9                             stockholder benefit ratio.    Plans with metrics for goals benefiting
10                             ratepayers but dependent on an earnings-per-share trigger are considered
11                             to benefit shareholders and opposed by staff. Staff's approach is set forth
12                             most recently, in 1OAL-963G by staff witness Kahl. The settlement in
13                             that case removed the dollar amount opposed by Kahl. All executive
14                             incentives are excluded from rates and typically no longer sought in
15                             company filings.

16           Hawaii            Hawaii does not allow incentive compensation to be included in rates. In
17                             Docket No. 6531 the commission agreed that bonus awards tied to
18                             company income and earnings benefit stockholders, not ratepayers. The
19                             commission further states, "... we believe that a utility employee,
20                             especially at the executive level, should perform at an optimum level
21                             without additional compensation. Ratepayers should not be burdened
                                                                                      40
22                             with additional costs for expected levels of service. "

23           Idaho             The commission's policy for evaluating incentive compensation plans
24                             involves determining who benefits, the customer or the company. This
25                             treatment has been refined in the recent Idaho Power rate case for plans
26                             which benefit the customer but require a financial trigger to be paid. For
27                             these plans the commission reduced the percentage allowed in rates. The
28                             commission also now does not include any executive compensation in
                                      41
29                             rates.

30           Kansas            Plans based solely on financial goals are not allowed. For executive
31                             incentive programs, the Commission also disallows 100% of plans based
32                             on financial measures and 50% for plans using a balance of financial and
33                             operational measures. The Commission has allowed in rates non-
     39
        Southern California Edison (Application#: 07-11-011, Decision#: 09-03-025).
     40
        Hawaii's policy is set forth in Docket No. 6531 in the October 17, 1991 Order No. 11317. Prior Dockets in which
     the commission disallowed incentive compensation include No. 3216, No. 4215, No. 4588 and No. 5114.
     41
        The Commission's focus on customer benefit is reflected in the direct testimony of Staff witness Leckie, and in
     the final order for the recent IPC General Rate Case IPC-E-08-10. For earlier examples of the basic policy, see
     Idaho Power Company Rate Case IPC-E-05-28, Corrected Motion for Approval of Stipulation 3/1/06, 6e, p. 4;
     Idaho Power Company IPC-05-28, Order No. 30035, p. 4/10.
     Direct Testimony of Mark E. Garrett                                                        Page 33 of 65
     Docket No. 39896
 1                              executive annual incentive programs that have no focus on profitability or
                                    .  42
 2                              earmng

 3            Louisiana         Traditionally incentive compensation for upper level management and
 4                              officers is excluded, while costs for lower level managers and employees
 5                              are allowed. The criteria used to evaluate plan design consider whether
 6                              the goals of each plan directly benefit ratepayers or shareholders. Stock
 7                              based compensation plans at ail levels are excluded.

 8            Minnesota         Minnesota distinguishes between incentive plans tied to financial triggers
 9                              (such as a threshold ROE), and plans tied to criteria benefitting the
10                              ratepayer. Plans based on goals which benefit ratepayers are allowed in
11                              rates, but their costs are capped at 25% of base salaries. 43 The portions of
12                              these plans that are allowed into rates are tracked and must be returned to
13                              ratepayers if they are not paid to employees. Executive plans are largely
                                             44
14                              not allowed.

15            Missouri          Missouri's treatment disallows incentives tied to goals benefitting
16                              primarily the stockholders (e.g. tied to earnings per share) while allowing
17                              plans with customer-specific goals (e.g. safety). Plans must also be
18                              reasonable. The Commission also allows only the amounts actually paid,
19                              not those accrued. The same criteria are used for executive pians and few
20                              are allowed. 45

21            Nevada            The commission excludes 100% of the long-term plans and all short-term
22                              plans directly related to financial performance. 46


     42
        In the litigated 2010 KCP&L rate case (10-KCPE-415-RTS) the Commission also stated that relying on peer
     group statistics "can result in a continuing upward spiral [instead] the Commission must examine the elements of
     incentive packages, and the behavior they in cent." The Commission held that a focus on profitability or earning
     might incent employee behavior "detrimental to customers."
     43
        This general policy is demonstrated in recent orders in the Minnesota Power and Ottertail rate cases: E002/GR-
     09-l l 51 and E002/GR-10-239 respectively.
     44
        Minnesota's general policy is demonstrated in recent orders in the Minnesota Power and Ottertail rate cases:
     E002/GR-09-l 15 l and E002/GR- l 0-239 respectively. See also Minnesota Power General Rate Case
     E002/GR/05/l 428.
     45
        See, e.g., in the latest Missouri American rate case (WR-2010-0131), not only were plans based on financial
     goals disallowed, but incentive payments based on customer satisfaction were disallowed due to the unreasonably
     small sample size used to establish a positive rating (a phone survey of927 of roughly 450,000 customers). The
     commission also removed incentive payments tied to lobbying and charitable activity. In the most recent case
     processed, the Ameren UE rate case, the company did not seek even short-term incentive compensation tied to
     earnings, providing further indication that staff's practice of disallowing financial performance based incentives is
     accepted by the companies. All incentive compensation adjustments were made not only to expense charges, but to
     construction charges as well. See also recent Kansas City Power and Light and Empire Electric District orders on
     the commission's website.
     46
        See, for example, the PUCN's final order in Docket 11-06006.
     Direct Testimony of Mark E. Garrett                                                           Page 34 of65
     Docket No. 39896
 1            New Mexico The commission does not favor incentive compensation plans that are tied
 2                       to financial goals and tends to allow in rates those based on operational
 3                       goals. This standard is applied to all levels of utility employees and tends
 4                       to eliminate the greater portion of executive plans. 47

 5            Oklahoma         The commission excludes incentive payments tied to financial
 6                             performance. From a practical perspective this means that all executive
 7                             stock plans are excluded and some portion of the annual cash plan for all
 8                             employees. Since the commission has not been able to determine in
 9                             recent cases the precise portion of the annual plans tied to financial
10                             measures, the commission has excluded 50% of the annual plans. 100%
11                             of the executive stock plans are excluded. 48

12           Oregon            The commission's general policy is to evaluate plans based on whether
13                             they benefit the customers or the company. Customer-based plans
14                             involving reliability, response speed, etc. are called "merit" (operational)
15                             plans. Company-based plans which track increases to the bottom line,
16                             ROE, etc. are called "performance" (financial) plans. 50% of the cost of
17                             merit plans is disallowed and 75% of the performance plans is disallowed.
18                             100% of officer bonuses are disallowed. 49

19           S. Dakota         The commission's general policy is to disallow the portion of incentive
20                             plans that are based on the company's financial performance. 5 Current      °
21                             treatment also includes disallowing both executive and non-executive
22                             management incentive compensation.            There are no incentive
23                             compensation plans for union employees. Several utilities have whole
24                             incentive programs that hinge on whether or not the company earns a
25                             certain return. These financial prerequisites cause the whole plans to be
26                             excluded from rates.

27           Texas             The general rule is that incentive payments designed to improve the
28                             financial performance of the utility are excluded. For example, in PUC
29                             Docket No. 28840, 51 the commission disallowed sixty-six percent (66%)
     47
        See Docket 07-00077-UT.
     48
        See e.g., AEP-PSO Cause No. PUD 06-285; OG&E Cause No. PUD 05-151; and ONG Cause No. PUD 04-610.
     49
         A recent order reflecting this policy can be found in Docket UE 197, Order No. 09-020.
     50
        In Docket No. EL 08-030 the settlement excluded bonuses related to "stockholder-benefitting financial goals."
     The settlement in Xcel rate case Docket No. EL09-009 removed payments based on financial performance
     indicators. In the settlement agreement signed July 7, 2010 in the Black Hills Power rate case Docket No. EL09-
     018 the Staff Memorandum states, "The settlement removes financial based incentive payments that were included
     in the capitalized labor costs for plant. Shareholders are the overwhelming beneficiaries of incentive plans that
     promote the financial performance of the Company and therefore should be responsible for the cost of such
     compensation."
     51
        Application ofAEP Texas Central Company for Authority to Change Rates, Docket No. 28840; SOAH Docket
     No. XXX-XX-XXXX, Final Order (August 15, 2005).
     Direct Testimony of Mark E. Garrett                                                         Page 35 of65
     Docket No. 39896
 1                             of AEP-Texas Central's test year incentive payments in the amount of
 2                             $4.2 million. This was the portion of the utility's incentive payments that
 3                             were based on financial performance measures. 52

 4            Utah             The commission's general policy is to allow in rates the parts of a plan
 5                             that are tied to ratepayer benefit and disallow the parts tied to financial
 6                             goals. Equity-based incentive compensation is excluded from rates. 53

 7           Washington Incentive plans are evaluated on a case by case basis. Incentives tied to
 8                      operational efficiency or other measures which benefit ratepayers are
 9                      allowed in rates and incentives based on return on earnings or other
10                      measures that benefit the shareholders are disallowed. 54

11           Wyoming           Employee incentive compensation plans are evaluated on a case by case
12                             basis, distinguishing between employee programs that benefit the
13                             ratepayer or the stockholders and requiring the benefitting party to pay.
14                             Executive incentive compensation plans are all excluded from rates.


     States that use another approach

15           Alaska            Incentive compensation is not an issue in rate cases in Alaska. There is
16                             no relevant regulation or policy.

17           Iowa              Incentive compensation is not typically an issue because few rate cases
18                             are litigated in this jurisdiction.        Mid-America has an incentive
19                             compensation plan but hasn't filed a rate case in many years. For the
20                             state's other utilities, it has been a long time since they have filed a rate
21                             case or had a rate increase. The standing treatment is to consider
22                             incentive compensation plans on a case by case basis and to evaluate
23                             whether they are reasonably and prudently incurred. Both of the investor
24                             owned utilities in Iowa are under rate freezes until 2013 and 2014.
25
26           Montana           Montana has no specific treatment directive and considers the issue on a
27                             case by case basis. In a recent North Western Energy rate case, as part of
28                             a stipulation agreement, the company took a portion of its incentive
     52
        See ALJ's Proposal for Decision at page 113 in PUC Docket No. 28840, SOAH Docket No. XXX-XX-XXXX, issued
     July 1, 2004. The PFD with respect to the treatment of incentive compensation was adopted by the Commission in
     its Final Order.
     53
        The recent final order in Docket 09-035-23 follows this general policy as does the order in Docket 07-35-93. See
     also Missouri Corp. Rate Case Docket 97-035-01, pp. 10-12; US West Communications Rate Case Docket 95-049-
     05.
     54
        See the Order in Pacific Power and Light Docket 061546.


     Direct Testimony of Mark E. Garrett                                                          Page 36 of65
     Docket No. 39896
 1                             compensation out of rates, but reserved the right to propose that it be
 2                             included in a later filing.
 3
 4           N. Dakota         Historically, North Dakota has followed the general policy that the
 5                             portion of incentive compensation that relates to shareholder earnings is
 6                             disallowed and the rest is included. Recently the commission chose to
 7                             consider overall compensation and determine whether it was reasonable
 8                             as compared to the market. 55 Executive incentive compensation is not
 9                             allowed in rates, and is typically not sought by the company.


10   Q:      HOW IS INCENTIVE COMPENSATION TREATED IN THE OTHER STATES

11           WHERE YOU HA VE PERSONAL EXPERIENCE?

12   A:      The states in which I routinely practice all follow the majority rule that incentive

13           expense associated with financial performance is excluded from rates. As a practical

14           matter, this means that some portion of all incentive plans are excluded in these

15           jurisdictions, as set forth in the summary below:

16                    In Arizona, the commission follows the same rule - that costs associated with

17           financial performance are excluded. In practice, this means that the costs of long-term

18           plans are excluded altogether and the costs of the short term annual cash plans are shared

19           50/50 between shareholders and ratepayers.              As examples, see APS 2008 rate case,

20           Decision 70360, Southwest Gas 2008 rate case, Decision 70665 and UNS Gas 2008 rate

21           case, Decision 70011.

22                    In Arkansas, incentive payments tied to financial performance measures that

23           benefit only the company such as stock-based plans and EPS measures are assigned


     55
       Other than Xcel, the utilities in North Dakota (Otter Tail and MDU) are highly diversified now (with mostly
     unregulated operations, e.g. MDU 90%). This allows utility executives to draw on the unregulated components for
     their compensation.


     Direct Testimony of Mark E. Garrett                                                       Page 37 of65
     Docket No. 39896
 1             l 00% to the shareholders while measures that benefit both the company and its

 2             customers are shared 50/50.

 3                     In Nevada, in the 2008 Nevada Power rate case, the commission excluded 100%

 4             of the long-term plan for executives and key employees of the company, based on the

 5             fact that these costs mainly benefit shareholders. 56 In Nevada Power's recent 2011 rate

 6             case, Docket No. 11-06006, the Company voluntarily excluded the costs of its long-term

 7             plan. With respect to short-term incentives, the commission excludes all plans directly

 8             related to financial performance.

 9                     In Oklahoma, the commission also excludes incentive payments tied to financial

10             performance. From a practical perspective this means that all executive stock plans are

11             excluded and some portion of the annual cash plan for all employees.              Since the

12             commission has not determined in recent years the precise portion of the annual plans

13             tied to financial measures, the commission has excluded 50% of the expense. All of the

14             long-term plan costs are routinely excluded. 57

15                     In Utah, costs associated with financial performance are excluded. The rule is

16             followed so closely that the utility typically no longer submits the cost of its long term

17             incentive plan for rate case recovery.




     56
          See Draft Order issued June 17, 2009 in Docket No. 08-12002, at page 138.
     57
          See, e.g., AEP-PSO Cause No. PUD 06-285; OG&E Cause No. PUD 05-151; and ONG Cause No. PUD 04-610.




     Direct Testimony of Mark E. Garrett                                                Page 38 of65
     Docket No. 39896
 1   Q:      WHY IS THE DISTINCTION BETWEEN FINANCIAL PERFORMANCE

 2           MEASURES          AND         OPERATIONAL        MEASURES          IMPORTANT           FOR

 3           INCENTIVE COMPENSATION ANALYSIS?

 4   A:      When incentive compensation payments are based on financial performance measures,

 5           the compensation agreement between shareholders and employees could be loosely

 6           stated in this manner: "if you will help increase shareholder earnings, we will pay you a

 7           bonus."    The intended beneficiaries to this agreement are the shareholders and the

 8           employees. Ratepayers have no stake in this agreement; therefore, they should bear none

 9           of the costs that result from such an agreement. If, instead, the agreement were stated in

10           this manner: "if you will help increase reliability and quality of service to the customers,

11           we will pay you a bonus," then, ratepayers would have a stake in the agreement, and

12           could share in a portion of the costs. However, so long as some portion of the incentive

13           plan is designed to increase earnings, that portion of the plan should be funded out of the

14           increased earnings the plan helps produce.

15

16   Q:      HOW MUCH OF THE COMPANY'S INCENTIVE COMPENSATION IS TIED

17           TO FINANCIAL PERFORMANCE?

18   A:      The Company estimates that 35% of the annual incentive plan payments are related to

19           financial performance measures. This percentage is a weighted average percentage that

20           includes: (1) all payments tied to Financial and Cost Control measures; and (2) one- third

21           of the payments tied to a combination of Cost Control, Safety and Operational



     Direct Testimony of Mark E. Garrett                                             Page 39 of65
     Docket No. 39896
                           58
 l            measures.          The Company also indicates that 100% of the equity-based long-term

 2            incentive plans and 100% of the stock option plans are related to financial

 3            performance. 59

 4

 5   Q:       WHAT         TYPES         OF      INCENTIVES            ARE       PROVIDED            TO      COMPANY

 6            EXECUTIVES?

 7   A:       Under the Company's plan, executives are provided three types of incentive

 8            compensation: (1) the Executive Annual Incentive Plan; (2) the Long-Term Cash

 9            Incentive plan; and (3) the Equity Ownership Plan, which provides stock options and

10            other stock-based awards to executives and other employees of the Company.

11

12   Q:       DO YOU RECOMMEND THE INCLUSION OF THE EXECUTIVE INCENTIVE

13            EXPENSE IN RATES?

14   A:       Generally, incentive compensation payments to officers, executives and key employees

15            of a utility company are excluded for ratemaking purposes, and I agree with this

16            treatment.        Executive stock-based compensation in particular is excluded in most

17            jurisdictions because stock-based compensation is, on its face, tied to financial

18            performance. Since officers of any corporation have a duty of loyalty to the corporation

19            itself and not to the customers of the company, these individuals typically put the

20            interests of the company first.            Undoubtedly, the interests of the company and the


     58
       This percentage is derived from Exhibit KGG-4 and is the weighted average of payments tied to financial and
     cost control measures. However, because Exhibit KGG-4 has been identified by the Company as a highly sensitive
     exhibit the exact derivation of this percentage is not provided in this "public" testimony, but is available for review.

     Direct Testimony of Mark E. Garrett                                                              Page 40 of65
     Docket No. 39896
 1              interests of the customer are not always the same, and at times, can be quite divergent.

 2              This natural divergence of interests creates a situation where not every cost associated

 3              with executive compensation is presumed to be a necessary cost of providing utility

 4              service.

 5                       It has been my experience that some utilities no longer seek recovery of

 6              executive long-term incentive compensation, since long-term executive incentive plans,

 7              such as stock option plans, are specifically designed to tie executive compensation to the

 8              financial performance of the company to further align the interests of the executives with

 9              those of the shareholders. Since the compensation of the employee is tied over a long

10              period of time to the company's stock price, it creates an incentive for the employee to

11              make business decisions from the perspective of long-term shareholders.                      This

12              intentional alignment of employee and shareholder interests means the costs of these

13              plans should be borne solely by the shareholders. It would be inappropriate to require

14              ratepayers to bear the costs of incentive plans designed to encourage utility executives to

15              put the interest of the shareholders first, especially when the interest of the shareholder is

16              directly bolstered by increases in utility rates.

17                       While many regulators are inclined to exclude all executive bonuses, incentive

18              compensation and supplemental benefits from utility rates, my recommendation in this

19              testimony merely follows the Texas rule               which excludes incentives tied to financial

20              performance measures - effectively eliminating most of the executive incentives.




     59
          See ETI responses to Cities' RFI 10-9(k) and Cities' RFI 10-lO(k).
     Direct Testimony of Mark E. Garrett                                                      Page 41 of65
     Docket No. 39896
 1   Q:      IS YOUR RECOMMENDATION TO EXCLUDE ALL EQUITY INCENTIVE

 2           COMPENSATION CONSISTENT WITH THE TREATMENT OF INCENTIVES

 3           IN THE OTHER STATES WHERE YOU REGULARLY PRACTICE?

 4   A:      Yes.    Oklahoma, Nevada and Utah all follow the same general rule that excludes

 5           incentive compensation tied to financial performance measures. This means that long-

 6           term equity incentive plans are all excluded. For example, in Oklahoma, in each of the

 7           most recently litigated rate cases for the three major utilities in that state, the commission

 8           has excluded 100% of the utilities' long-term incentive compensation plans. Likewise,

 9           in Nevada, the commission excluded 100% of the long-term incentive compensation

10           plan costs in Nevada Power's 2008 rate case. In the Company's 2011 rate case, the

11           utility voluntarily excluded the long-term incentive costs.              In Utah, PacifiCorp also

12           voluntarily removes all costs associated with its long-term incentive compensation

13           plans. 60 The table below sets forth the most recent treatment of long-term incentive

14           compensation for the major utilities in these jurisdictions.




     60
       In PacifiCorp's last two general rate case, Docket No. 07-035-93 and Docket No. 08-035-38, the Company did
     not seek recovery of its long-term executive compensation plans.




     Direct Testimony of Mark E. Garrett                                                      Page 42 of65
     Docket No. 39896
                                                 TABLE: 2

           LONG-TERM INCENTIVE TREATMENT IN OKLAHOMA, NEV ADA AND UTAH


            Utility Company                  Amount Excluded                    Docket Number

     AEP/PSO                                   100% Excluded             Cause Nos. PUD 06-285;08-144
     Oklahoma Gas & Electric                   100% Excluded             Cause No. PUD 05-151
     Oklahoma Natural Gas                      100% Excluded             Cause No. PUD 04-610
     Nevada Power                              l 00% Excluded            Docket No. 08-12002; 11-06006
     PacifiCorp                                I 00% Excluded            Docket No. 08-035-38



 1   Q:      HOW IS EQUITY INCENTIVE COMPENSATION TREATED IN OTHER

 2           STATES?

 3   A:      As shown in the Garrett Group's Incentive Survey, most states follow guidelines similar

 4           to those described above for Texas, Oklahoma, Nevada and Utah, that disallow incentive

 5           pay associated with financial performance. As a result, equity-based incentives typically

 6           are not allowed in most states. A synopsis of the survey results from each state was

 7           included earlier in this section of testimony, with the treatment of executive incentives in

 8           each state underlined. According to the survey, the following western states exclude all

 9           or virtually all executive incentive pay: Oregon, California, Nevada, Idaho, Utah, South

10           Dakota, Oklahoma, Wyoming, North Dakota, Missouri, Arkansas, Louisiana and

11           Minnesota.    Other states, like Washington, Missouri and Texas, apply the financial

12          performance rule, which has the effect of excluding executive incentives, especially

13           stock-based awards.




     Direct Testimony of Mark E. Garrett                                             Page 43 of65
     Docket No. 39896
 1   Q:         WHEN         UTILITIES            DO    SEEK        TO     INCLUDE            EXECUTIVE     STOCK

 2              COMPENSATION                 IN    RATES,        WHAT         RATIONALE          IS   GENERALLY

 3              PROVIDED?

 4   A:         Generally, utilities argue that executive incentives are part of an overall compensation

 5              package that is designed to attract and retain qualified personnel.                   Generally, the

 6              rationale is that some other utilities may offer incentive plans to their executives, thus a

 7              company runs the risk of not being able to compete for key personnel if it does not offer

 8              a comparable plan. 61

 9

10   Q:         IS THIS ARGUMENT PLAUSIBLE?

11   A:         No. The common problem with the Company's "total compensation package" argument

12              is that when an incentive payment is based on achieving financial performance goals

13              there should be a financial benefit to the company that comes from achieving these

14              goals. This financial benefit should provide ample additional funds from which to make

15              the incentive payments. If not, the plan was poorly conceived. Thus, a utility is not

16              placed at a competitive disadvantage when incentive payments tied to financial

17              performance are not collected through rates, because the funding for these payments is

18              available from the additional earnings the incentive plans help achieve.

19                       Further, when utilities, such as ETI, compete with other utilities for qualified

20              executives, and the executive incentive compensation plans of the other utilities are not

21              being recovered through rates, ETI is not at a disadvantage when its equity incentive

     61
          See, for example, the Direct Testimony of Jay C. Hartzell at page 7, lines 10-13.
     Direct Testimony of Mark E. Garrett                                                          Page 44 of65
     Docket No. 39896
 1           compensation is excluded as well. Since most states exclude equity incentive pay as a

 2           matter of course, and many others exclude equity incentives as a practical matter, ETI

 3           would actually be given an unfair advantage if its equity plans were included in rates.

 4           The fact that other utilities may offer equity incentive plans is not relevant; what is

 5           relevant is the fact that other utilities typically are not recovering the costs of these plans

 6           in rates. The Nevada Commission articulated this important ratemaking concept in its

 7           order disallowing Nevada Power's long-term incentive plan in the Company's 2008

 8           general rate case.

 9                    Therefore the Commission accepts BCP's and SNHG's recommendations
10                    to disallow recovery of expenses associated with LTIP. Both parties
11                    provide a valid argument that this type of incentive plan is mainly for the
12                    benefit of shareholders. Further, both BCP and SNHG provide examples
13                    of numerous other jurisdictions that do not allow the recovery of these
14                    costs and, therefore, disallowance in this instance wouid not place NPC in
15                    a competitive disadvantage. 62 (Emphasis added).


16   Q:      IS THERE OTHER EVIDENCE THAT THE COMPANY WILL NOT BE

17           DISADVANTAGED BY A DISALLOWANCE OF INCENTIVE EXPENSE?

18   A:      Yes. According to Mr. Gardner, the Company's total payroll costs for 2011, including

19           both base pay and incentives, was 10% above market. 63 Most of these above-market

20           payroll costs relate to the Company's incentives. The Company's incentive levels are

21           63% above-market and the Company's base pay levels are 2% above market, resulting in

22           a total above-market level of 10% for both base pay and incentives. 64 The above-market


     62
        See Final Order in Docket 08-12002 at paragraph 549. NPC did not seek recovery of its LTIP in the 2011 rate
     case, Docket No. 11-06006.
     63
        See Table 5 at page 26 of Mr. Gardner's Direct Testimony.
     64
        See ETI response to Cities' RFI l 8-8(b ).

     Direct Testimony of Mark E. Garrett                                                       Page 45 of65
     Docket No. 39896
 1              base pay is addressed earlier in this testimony.               The Company's 63% above-market

 2              incentive pay, however, is relevant in this section of testimony.            Cities' adjustment,

 3              proposed below, to reduce incentive compensation levels associated with financial based

 4              incentives (3 5% of the short term cash incentives and 100% for long term equity-based

 5              incentives), only reduces the Company's overall incentive compensation by 59%, which

 6              is less than the 63% that the incentives are above-market.

 7

 8   Q:         WHAT ADJUSTMENT DO YOU PROPOSE WITH RESPECT TO THE

 9              COMPANY'S INCENTIVE COMPENSATION COSTS?

10   A:         My proposed adjustment removes 35% of the annual incentive plan costs. This is the

11              weighted-average portion of the Company's plan that is tied to financial performance,

12              according to the Company. My adjustment also removes 100% of (1) the Long-Term

13              Incentive plan and (2) the Stock Option awards. These plans are clearly based entirely

14              upon the financial performance of the Company. Stock options are financial-based on

15              their face, and the Company admits that the Long-Term awards are based on financial

16              performance. 65




     65
          See ETI responses to Cities' RFI I0-9(k) and Cities' RFI 10-lO(k).




     Direct Testimony of Mark E. Garrett                                                     Page 46 of65
     Docket No. 39896
 1   Q:      DOES THE AMOUNT YOU IDENTIFIED IN THE ANNUAL PLANS AS

 2           ASSOCIATED WITH FINANCIAL PERFORMANCE DIFFER FROM THE

 3           AMOUNT IDENTIFIED BY THE COMP ANY?

 4   A:      Yes. The Company identified 14.1 % costs in the annual incentive plans as associated

 5           with financial performance. 66 The Company divided the plans into four categories: (1)

 6           financial performance goals; (2) cost control goals; (3) operational goals; and (4) safety

 7           goals. 67 The Company included only category (1 ), financial performance goals, in the

 8           14.1 % tied to financial performance. 68           This category includes goals tied solely to

 9           increasing shareholder wealth such as earnings per share, shareholder returns, and stock

10           price. 69 The Company did not include category (2), cost control goals, as goals tied to

11           financial performance, but does acknowledge that this category should be included based

12           on prior Commission orders. 70

13

14   Q:      WHAT DID YOU DO TO ARRIVE AT YOUR CALCULATED 35% FOR

15           FINANCIAL PERFORMANCE COMPONENT OF THE ANNUAL INCENTIVE

16           PLANS?

17   A:      To arrive at 35%, I included costs in category (2), cost control goals, as related to

18           financial performance.        I also included one-third of the costs in category (5), which

19           included a combination of cost control, safety and operational goals. When categories

20           (1) and (2) and one-third (1/3) of category (5) are combined, the amount related to


     66
        Direct Testimony of Kevin G. Gardner at page 30, line 7.
     67
        Highly Confidential Exhibit KGG-4, page I of 1.
     68
        Calculated from the information on Highly Confidential Exhibit KGG-4.

     Direct Testimony of Mark E. Garrett                                                 Page 47 of 65
     Docket No. 39896
1           financial performance is 35%. I included the category (2), cost control goals, as related

2           to financial performance because, in my experience, this is the typical treatment for cost

3           control measures.       Since the Company retains all of the savings generated from cost

4           cutting measures between rate cases, it should pay the related incentives out of the

5           savings these cost cutting measures generate. Moreover, this treatment is consistent with

6           the regulatory treatment used by this Commission in the past on this issue. 71

7

8   Q:      HOW WAS YOUR ADJUSTMENT DEVELOPED?

9   A:      The following table shows the amount of Cities' proposed adjustment for incentives:


    69
       From the Description of Goals box at the bottom of page l of Highly Confidential Exhibit KGG-4.
    70
       See Direct Testimony of Jay C. Hartzell, PhD, at page 9, lines 9-13.
    71
       See Id. at page 8, lines 9-13 and footnote 1.




    Direct Testimony of Mark E. Garrett                                                       Page 48 of65
    Docket No. 39896
                        Table 3: Cities' Incentive Compensation Adjustment

                                                         Amount          % Tied to
                                                                                           CITIES'
     Incentive Compensation Plans                      Included in       Financial
                                                                                          Adjustment
                                                      Cost of Service   Performance
     Management Incentive Plan                            $4,749,198        35%              $1,862,219
     Exempt Incentive Plan                                $1,858,337        35%                $650,418
     Team Share Incentive Plan                              $153,447        35%                 $53,706
     Team Share - Bargaining Employees                      $384,877        35%               $134,707
     Executive Annual Incentive Plan                      $1,483,447        35%               $519,206
     Long-Term Incentive Plans                              $815,608       100%               $815,608 I
     Equity Ownership Plans                               $4,561,367       100%              $4,561,367

     CITIES' Adjustment                                 $14,187,774                          $8,397,2321
                                                  I                                   I

 1   Q:      ARE THERE OTHER REASONS THE COMMISSION COULD CONSIDER A

 2           LARGER ADJUSTMENT TO INCENTIVE PAY?

 3   A:      Yes.   The Company's "allowable" incentive payments, m effect, those not tied to

 4          financial goals, are tied primarily to operational goals, made up of "reliability, customer

 5           service, capacity factor and community relations." In the test year, the Company made

 6           substantial incentive payments based on employees achieving some perceived acceptable

 7           level with respect to these goals.   However, these payments seem inconsistent with

 8           Entergy's ratings in the annual J.D. Power's Report on Customer Satisfaction for

 9           Residential customers. 71 The J.D. Power and Associates Reports are widely recognized

10           and unbiased. The J.D. Power's report ranks utilities based on customer satisfaction. The

11           Entergy companies did not fare well, with Entergy Arkansas and Entergy Louisiana

12           ranking below average and Entergy New Orleans ranking 124th out of the 125 utilities



     Direct Testimony of Mark E. Garrett                                              Page 49 of65
     Docket No. 39896
 1              ranked in the 2011 report. Entergy Texas ranked only slightly above average. The poor

 2              showing of the Entergy companies in general in an independent, objective customer

 3              satisfaction evaluation report brings into question whether ratepayers should be required

 4              to pay any of the "allowable" ETI incentives that are based on customer service and

 5              community relations.

 6

 7   Q:         IS THERE EVIDENCE THAT THE ANNUAL INCENTIVE PLANS ACTUALLY

 8              MAY BE TIED TO FINANCIAL PERFORMANCE AT LEVELS HIGHER THAN

 9              THE 35% DIRECTLY RELATED TO STOCK PRICE GOALS AND COST

10              CONTROL GOALS?

11   A:         Yes. Each Entergy business unit designs its incentive targets based on goals that include

12              both financial-performance and operational goals such as spending level goals, cost

13              constraint goals, reliability goals, safety goals and customer service goals. However, the

14              Company still uses the EAM (Entergy Achievement Multiplier) to arrive at the amount

15              to be funded each year.          In the past, the EAM was a composite of the Company's

16              earnings per share increase and operating cash flows, and was used as a performance

17              target. Now, the EAM operates as a funding mechanism for all plans to ensure that

18              adequate additional funds exist to pay the incentives, and as a performance target for

19              certain executives. 73 This indicates that all incentive payments are directly dependent on

20              the financial success of the Company each year. For ratemaking purposes, this means

21              that the entire amount of incentive payments could be viewed as tied to financial


     72
          J.D. Power and Associates 2011 Electric Utility Residential Customer Satisfaction Study.
     Direct Testimony of Mark E. Garrett                                                             Page 50 of65
     Docket No. 39896
 I           performance and disallowed on this basis. 74            If that were the case, the adjustment

 2           necessary to remove the entire amount of incentive payments from the cost of service

 3           would be $14,187,744.

 4

 5   Q:      HOW SHOULD THE COMMISSION TREAT INCENTIVE COMPENSATION

 6           IN THIS CASE?

 7   A:      At a minimum, the Commission should continue to follow the rule observed in Texas

 8           and in most other jurisdictions, by disallowing for ratemaking purposes all incentive

 9           payments associated with financial performance goals.              This approach would exclude

10           the portion of annual incentive costs associated with stock price and cost control goals -

11           as well as the costs of the long-term incentive plan and the stock option plans. In light of

12           the overwhelming trend against including financial-based incentives in rates, and

13           considering the current national economic downturn and the economic shortfalls being

14           experienced in Texas in particular, I believe the Commission should continue to follow

15           the approach to incentive compensation that protects ratepayers against even the

16           appearance of being forced to pay costs designed to increase shareholder wealth. A

17           policy that includes incentive payments based on financial performance in rates, as

18           proposed by the Company, has the effect of forcing ratepayers to become captive

19           contributors to the financial prosperity of one company. Cities' proposed adjustment


     73
        See Direct Testimony of Kevin G. Gardner at page 17-18.
     74
        In Oklahoma, the Commission disallowed l 00% of the ONEOK, Inc. incentives for regular employees, because,
     although many of the goals were purportedly customer-related goals, actual funding of the incentive payments
     depended on the financial success of the company each year. See Cause Nos. PUD 91-1190 and PUD 2004-610.



     Direct Testimony of Mark E. Garrett                                                     Page 51 of65
     Docket No. 39896
            decreases pro forma operating expense by $8,397,232, and is set forth at Exhibit MG-

 2          2.10.

 3                   In the alternative, the Commission could consider a larger adjustment based on

 4          the fact the Company's performance with respect to operational goals, such as customer

 5           service and customer satisfaction, should not be included in rates if the Company's

 6          performance in these areas is clearly below average. Based on the assessment of an

 7           independent third party in the J.D. Power report, the Company's performance in

 8           customer satisfaction is below average and, thus, the Commission may determine that a

 9           larger disallowance of incentive compensation is appropriate.

10

11   Q:      ARE YOU PROPOSING ANY OTHER ADJUSTMENTS FOR INCENTIVE

12           COSTS?

13   A:      Yes. Disallowed incentive costs should not just be removed from operating expense but

14           should also be removed from rate base as well.          When a cost is disallowed for

15           ratemaking purposes it must be removed from both operating expense and rate base.

16           Since a significant portion of the Company's incentive payments are capitalized each

17          year into the plant accounts, these amounts are included in pro forma rate base where

18           they will earn a return and be recovered through depreciation rates if not adjusted in this

19           case. Thus, it is necessary to reduce the amount of incentives capitalized in rate base by

20           the same percentage disallowed in operating expense.        In effect, capitalized annual

21           incentives should be reduced by 35% and capitalized stock-based incentives should be

22           reduced by 100%.

     Direct Testimony of Mark E. Garrett                                            Page 52 of65
     Docket No. 39896
 1   Q:      HAVE YOU BEEN ABLE TO QUANTIFY THIS ADJUSTMENT?

 2   A:      Yes.   In response to Cities' 10th Set of RFis, the Company provided the amounts

 3           capitalized for each incentive plan from 2008 through the end of the test year. For my

 4           proposed adjustment, I included capitalized incentives from 2008 through the beginning

 5           of the test year but did not include incentive capitalized during the test year, as test year

 6           incentives may still be recorded in the CWIP accounts and not included in pro forma rate

 7           base in this case.

 8                   Cities' proposed adjustment decreases proforma rate base by $9,835,111 and is

 9           set forth at Exhibit MG-2.10. This adjustment removes 35% of the annual incentives in

10           rate base and 100% of the equity-based incentives, from the 2007 inception of ETI

11           forward excluding the test year.

12

13   Q:      ARE YOU PROPOSING ANY OTHER ADJUSTMENTS FOR INCENTIVE

14           COSTS?

15   A:      Yes. Accumulated deferred federal income tax (ADFIT) associated with disallowed

16           long-term incentive plans should be removed from rate base. This means that rate base

17           should be reduced by a net $694,730 debit balance in ADFIT accounts associated with

18           the Company's long-term incentive and stock option plans. The calculations for this

19           adjustment are set forth at Exhibit MG2. l 0.




     Direct Testimony of Mark E. Garrett                                              Page 53 of65
     Docket No. 39896
     SECTION IV. F.              SUPPLEMENTAL EXECUTIVE RETIREMENT PLANS

 1   Q:         PLEASE        DESCRIBE         THE      COMPANY'S            SUPPLEMENTAL   EXECUTIVE

 2              RETIREMENT PLANS.

 3   A:         The Company provides supplemental retirement benefits to highly compensated employees

 4              of the Company. These supplemental retirement plans for highly compensated individuals

 5              are provided because benefits under the general retirement plans are subject to certain

 6              limitations under the Internal Revenue Code (the "Code"). As such, these types of plans are

 7              often referred to as non-qualified plans. Benefits payable under these non-qualified plans

 8              are typically equivalent to the amounts that would have been paid but for the limitations

 9              imposed by the Code.         In general, the limitations imposed by the Code allow for the

                                                                                                         75
10              computation of benefits on annual compensation levels of up to $245,000 for the year.

11              Retirement benefits on compensation levels in excess of the $245,000 limitation are paid

12              through supplemental plans.          Supplemental retirement plans for highly compensated

13              employees are designed to provide benefits in addition to the benefits provided under the

14              general pension plans of the company.

15                       The Company has three non-qualified retirement plans for highly compensated

16              employees:

17                       1) Pension Equalization Plan;
18                       2) System Executive Retirement Plan; and
19                       3) Supplemental Retirement Plan.



     75
          The limits are $225,000 for 2007, $230,000 for 2008 and $245,000 for 2009.




     Direct Testimony of Mark E. Garrett                                               Page 54 of65
     Docket No. 39896
 1              The first plan covers all employees with compensation levels above the $245,000 limitation

 2              under the internal revenue code. The other two plans are supplemental plans for executives

 3              only. Benefits are paid out of the general funds of the Company.

 4

 5   Q:         WHAT AMOUNTS WERE INCLUDED IN PROFORMA OPERATING EXPENSE

 6              FOR THE EXECUTIVE PENSION PLAN?

 7   A:         The amount of non-qualified supplemental retirement plan costs included in the filed cost-

 8              of-service was $2, 114,931. Of this amount, direct ETI costs were $721,643 and the amount

 9              allocated from ESI was $1,393,288. 76

10

11   Q:         WHAT DO YOU RECOMMEND FOR THE SUPPLEMENTAL EXECUTIVE

12              RETIREMENT PLAN COSTS?

13   A:         I recommend that shareholders pay for the costs of the supplemental executive

14              retirement plans. This means that ratepayers will pay for all of the executive benefits

15              included in the Company's regular pension plans, and that shareholders pay for the

16              additional executive benefits included in the supplemental plan.         For ratemaking

17              purposes, shareholders should bear the additional costs associated with supplemental

18              benefits to highly compensated executives, since these costs are not necessary for the

19              provision of utility service, but are instead discretionary costs of the shareholders

20              designed to attract, retain and reward highly compensated employees. However, because

21              officers of any corporation have a duty of loyalty to the corporation, these individuals


     76
          See ETI responses to Cities' RFI 12-47.
     Direct Testimony of Mark E. Garrett                                              Page 55 of 65
     Docket No. 39896
 1              will put the interests of the company first. This creates a situation where not every cost

 2              associated with executive compensation is presumed to be a cost appropriately passed on

 3              to ratepayers.      Many regulators are inclined to exclude executive bonuses, incentive

 4              compensation and supplemental benefits from utility rates, understanding that these costs

 5              would be better borne by the utility shareholders. 77

 6

 7   Q:         HOW IS SERP TREATED IN OTHER STATES?

 8   A:         Although I have not conducted a comprehensive study of SERP treatment in other states,

 9              I know that SERP is disallowed in the states of Oregon, 78 Idaho 79 and Arizona. 80

10              Moreover, in Nevada, the commission disallowed all SERP expense in Docket Nos. 01-

11              10001 and 03-10001, and in Docket Nos. 06-l 1022and 08-12002, the Nevada

12              Commission disallowed a portion of SERP costs.

     77
          For example, this Commission excluded SERP costs in PSO's last rate case, PUD 200600285.
     78
          See Oregon Public Utilities Commission, Order No. 01-787, September 7, 2001, page 44.
                The Commission has not allowed recovery of SERP expenses in other utility rate cases.
                PacifiCorp has not persuaded us that it is necessary to pay SERP to hire and retain
                executive officers. The SERP costs are not allowed."
     79
        See Idaho Public Utilities Commission Order No. 32196 issued February 28, 2011 in Rocky Mountain Power's
     rate case, Case No. Pac-E-10-07:

                The Commission finds Staffs argument persuasive and finds it reasonable to disallow Company
                recovery of SERP costs of $2.6 million (total Company) in this case. The Company has not
                demonstrated that the costs are related to providing services to southeast Idaho. The responsibility
                for generous severance benefits for executives, we find, is the responsibility of the Company and
                its shareholders, not Idaho customers.
     80
       The Arizona Corporation Commission has issued several decisions in which it denied rate recovery for SERP
     expenses. See 258 PUR 4th 353 (2007) Re Arizona Public Service Company, 247 PUR 4th 243 (2006), In Re
     Southwest Gas Corp., 2008 WL 2332953 (Arizona Corp Commission Decision 70360, May 27, 2008), In the
     Matter of the Application of UNS Electric, and 2007 WL 4731250 (Arizona Corp Commission Decision 70011,
     November 27, 2007) Re UNS Gas, Inc.



     Direct Testimony of Mark E. Garrett                                                              Page 56 of65
     Docket No. 39896
 1                   In Oklahoma, the Commission disallowed 100% of AEP/PSO's SERP expense in

 2           PSO's 2006 rate case, Cause No. PUD 200600285:

 3                   q.    Employee Benefits-Supplemental Executive Retirement Plan
 4                   ("SERP").
 5
 6                   PSO included $596,081 as Supplemental Executive Retirement Plan
 7                   ("SERP") in its cost-of-service.       The Commission adopts OIEC's
 8                   proposal to remove the SERP Expense from the revenue requirement in
 9                   this proceeding. The Commission adopts OIEC's recommendation that
I0                   ratepayers pay for all of the executive benefits included in PSO's regular
11                   pension plans and that shareholders pay for the additional executive
12                   benefits included in the supplemental plan.


13         Again, in PSO's 2008 rate case, Cause No. PUD 200800144, the Oklahoma commission

14         disallowed 100% of the Company's SERP expense.

15                   11.     Supplemental Executive Retirement Plan ("SERP")

16                   The AG and OIEC recommend reductions to reflect the elimination of
17                   SERP expense from PSO' s cost of service. Staff proposed no adjustment
18                   to PSO's recommendation. SERP is AEP's non-qualified defined benefit
19                   retirement plan that allows PSO argued allows AEP the flexibility to
20                   attract and retain key employees and provides benefits that cannot be
21                   provided under AEP's qualified defined benefit plans. PSO stated that
22                   the combined plans, of which SERP is a part, allow employees to
23                   accumulate an appropriate level of replacement income upon retirement.
24                   According to PSO, SERP plans and other benefits are part of a market
25                   competitive benefits program for the utility industry and large employers
26                   in general. The Commission finds that the SERP expenses do not provide
27                   a benefit to the ratepayers of PSO and therefore adopts the
28                   recommendation of the AG and OIEC to deny recovery of these costs
29                   from PSO's ratepayers.




     Direct Testimony of Mark E. Garrett                                           Page 57 of65
     Docket No. 39896
 I   Q:      WHAT IS THE AMOUNT OF YOUR ADJUSTMENT?

 2   A:      Cities' proposed adjustment, in the amount of $2,114,931, removes the costs of the non-

 3           qualified retirement plans from cost of service. The adjustment is set forth at Exhibit

 4           MG-2.11.



     SECTION IV. G.          ABOVE-MARKET EMPLOYEE BENEFITS

 5   Q:      WHAT IS THE ISSUE WITH RESPECT TO ABOVE-MARKET EMPLOYEE

 6           BENEFITS?

 7   A:      This section of my testimony addresses the above-market value of the Company's

 8           employee benefit plans. At page 41 of his direct testimony, Mr. Gardner admits that the

 9           value of the Company's employee benefit plans is 14% above market when compared to

10           a peer group of Fortune 500 companies.

11

12   Q:      HA VE YOU PROPOSED AN ADJUSTMENT TO THE BASE PAY LEVEL

13           REQUESTED IN RATES?

14   A:      Yes. From a ratemaking perspective, ratepayers are only required to pay the necessary

15           costs of providing utility service. Although the Company is free to pay its employees

16           above-market wages and above-market benefits, ratepayers should only be asked to pay

17           market-based prices for employee costs. For purposes of this adjustment, the calculation

18           of market-based wages is based the Company's own calculation.         Because ratepayers

19           are experiencing the effects of perhaps the most severe financial downturn in the past 30

20           to 35 years, it would be particularly unfair at this time to ask captive ratepayers to pay

     Direct Testimony of Mark E. Garrett                                           Page 58 of65
     Docket No. 39896
1               above-market wages for utility services.               As a result, I am recommending a 14%

2               adjustment to the employee benefits expense included in proforma rates.

3

4   Q:         HOW IS YOUR ADJUSTMENT CALCULATED?

5   A:         The adjustment, calculated in the table below, removes 14% of the Company's identified

6              employee benefits expense. The adjustment can be seen at Exhibit MG 2.9.



                               Table 4: Cities' Employee Benefits Adjustment81

                                                                                                    Total Amount in
    Employee Benefit Plans                                            ETI                    ESI     Cost of Service
    Medical I Dental                                                  4,476,874       2,504,140             5,981,014
    LTD                                                                 131,273         58,058                189,331
    Life                                                                142,636         79,328                221,964
    Retirement Plans                                                  7,324,753       5,711,755            13,036,508
    Executive F'"etirement Plans                                        721,643       1,393,288                     0

    Totals                                                          12,797,179        9,746,569           20,426,817

    Above Market Percentage                                                                                       14%

    CITIES' Adjustment                                                                                    $2,860,034




    81
         The information in this table is from ETI's response to Cities' RFI 18-l(d)(vii).




    Direct Testimony of Mark E. Garrett                                                            Page 59 of65
    Docket No. 39896
     SECTION IV. H.             ADV ALOREM TAX EXPENSE

 1   Q:      WHAT IS THE COMPANY PROPOSING AS AN AD VALOREM TAX

 2            EXPENSE ADJUSTMENT?

 3   A:       The Company is proposing a 10. 81 % increase in property tax expense based on a

 4           weighted average projected increase in net plant and net operating income for 2011. 82

 5            The Company asserts that both net plant and net income are drivers in determining a

 6            company's calculation for property tax assessment purposes. 83 The Company gives its

 7           projected net plant increase a 20% weighting and its projected net income increase an

 8            80% weighting and then adds an additional 1% for "Annual Tax Rate Creep." 84 The

 9            Company's 10.81 % projected increase in property tax valuation results in an adjustment

10            of $2,592,417 to test year property tax expense.

11

12   Q:       DO YOU AGREEE WITH THE COMP ANY'S PROPOSED ADJUSTMENT?

13   A:      No. The Company's proposed adjustment is based on estimates and seems unreasonably

14           high when compared to actual valuation increase over the last couple of years. The

15            Company provided actual valuation increases for 2010 and 2011 in Chart 1 at page 8 of

16            Patricia Galbraith's direct testimony. These actual valuation increases were 7.0% in

17            2010 and 4.2% in 2011, much less than the Company's predicted 10.81% increase for

18            2012.




     82
        See AJ25, Adjustment to Property Tax Expense.
     83
        See Direct Testimony of P. Galbraith at page 7, line 16.
     84
        See AJ25, Adjustment to Property Tax Expense.

     Direct Testimony of Mark E. Garrett                                          Page 60 of65
     Docket No. 39896
 1   Q:         WHAT ADJUSTMENT WOULD YOU RECOMMEND FOR PROPERTY TAX

 2              EXPENSE?

 3   A:         I would recommend a more conservative approach when estimating tax increases. Since

 4              actual valuation increases have averaged about 5.6% over the last two year period, I

 5              would recommend an increase in that range for ratemaking purposes. Since property tax

 6              is typically assessed on the appraised value of property located within the jurisdiction of

 7              the taxing authority, 85 I recommend an adjustment based upon the Company's estimated

 8              percentage increase in net plant for 2011, which is 3.73%. 86 With a 1% "Tax Rate

 9              Creep" added, this results in a 4.73% increase, which is much closer to the Company's

10              actual average valuation increase of 5.6%. A 4.73% increase in property tax expense

11              results in an increase to test year property tax expense of $1.1 million. Using a 4.73%

12              increase instead of the Company's recommended 10.81 % increase results in an

13              adjustment to pro forma cost of service of $1,457,975. This adjustment can be seen at

14              Exhibit MG2.13.



     SECTIONV.                   MISO TRANSITION EXPENSE ADJUSTMENT

15   Q:         WHAT IS THE ISSUE REGARDING MISO TRANSITION EXPENSE?

16   A:         In this case, the Company is requesting deferred accounting treatment for its MISO

17              transition costs. 87 The Company is also proposing a pro forma adjustment to include its

18              estimated MISO transition costs in rates in the event its requested deferred accounting

     85
          See P. Galbraith Direct Testimony at page 6, line 16.
     86
          See AJ25.
     87
          See the Direct Testimony and the Supplemental Testimony of Mr. Jay A. Lewis.

     Direct Testimony of Mark E. Garrett                                                 Page 61 of 65
     Docket No. 39896
 1           treatment is not approved. Cities oppose the Company's requested deferred accounting

 2           for the MISO transitions costs in the testimony of Mr. James Brazell. In my testimony, I

 3           address the Company's pro forma adjustment to recover MISO transition costs in the

 4           event the deferred treatment is not approved.

 5

 6   Q:      WHAT IS THE COMPANY PROPOSING FOR A PROFORMA ADJUSTMENT

 7           TO RECOVER ESTIMATED MISO TRANSITION COSTS?

 8   A:      The Company's adjustment increases cost of service by $4 million annually to recover a

 9           3-year amortization of estimated MISO transition costs of $12 million. 88

10

11   Q:      DO YOU AGREE WITH THE COMP ANY'S PROPOSED ADJUSTMENT IN

12           THE EVENT DEFERRED ACCOUNTING IS NOT APPROVED FOR MISO

13           TRANSITION COSTS?

14   A:       No. The Company's requested $4 million annual expense level is inconsistent with the

15           Company's own projections of anticipated cost levels provided in response to Cities' 6-

16           3. The test year level for these expenses was $916,535. 89 The actual expenses incurred

17           m 2011, January through November, were only $2.513 million. 90                        Annualized, this

18           would be $2.742 million. For 2013, the Company is expecting to incur an expense level


     88
        See adjustment AJl 6.23L. The Company also removes test year expense of $9 l 6K so that the amount included
     in pro forma expense is $4 million.
     89
        See AJl 6L is ETI Workpapers.
     90
        This amount appears in ETI's response to Cities' 6-3(b), Confidential Attachment 2. Attachment 2 is not being
     provided as an exhibit to this testimony because of its confidential designation. Cities, however, is using the
     $2,513 ,932 total from Attachment 2 with permission of the Company.



     Direct Testimony of Mark E. Garrett                                                         Page 62 of65
     Docket No. 39896
 1            of $2.587 million, 91 which is considerably less than the pro forma level of $4 million.

 2            The projected 2012 level of $8.9 million is higher than $4 million, but the 2012 is an

 3            estimated level and is not consistent with actual 2011 results, and, 2012 will be half-over

 4            by the time new rates go into effect. In my opinion, the actual 2011 level of about $2. 7

 5            million or the expected 2013 level of about $2.6 million would be the outside range of

 6            what the Commission would use for setting prospective rates. However, these levels, on

 7            a going forward basis, are not sufficiently known and measurable to include for

 8            ratemaking purposes. It is unknown at this point whether the move to MISO will even

 9            be approved by this or other commissions and whether the Company will continue to

10            incur costs toward a MISO transition. Consequently, we are left with only the test year

11            level as the level to include in rates.

12

13   Q:       HOW IS YOUR ADJUSTMENT CALCULATED?

14   A:       My recommendation to reduce the Company's requested level of $4 million to the actual

15            test year level of $916,535 results in an adjustment of $3,083,462. This adjustment can

16            be seen at Exhibit MG2.14.




     91
       This amount appears in ETI's responses to Cities' 6-3(a)and (c), Confidential Attachment 1. Attachment l is not
     being provided as an exhibit to this testimony because of its confidential designation. Cities, however, is using the
     $2,587,943 total from Attachment 1 with permission of the Company.




     Direct Testimony of Mark E. Garrett                                                           Page 63 of65
     Docket No. 39896
     SECTION VI.                 RIVER BEND DECOMMISSIONING EXPENSE

 1   Q:         WHAT IS THE ISSUE REGARDING THE RIVER BEND DECOMMISSIONING

 2              EXPENSE?

 3   A:         In its application, the Company has included River Bend decommissioning costs in the

 4              amount of $2,019,000.          This level is based on an agreement of the parties in the

 5              Company's 2009 rate case, Docket No. 37744. 92                  In this case, the Company was

 6              requested to provide the annual decommissioning expense responsibility for Texas retail

 7              customers required for River Bend 70% calculated using the most current Texas

 8              Jurisdictional decommissioning fund balance and assuming the escalation rates agreed to

 9              in the settlement of Docket No. 37744. The Company was also asked to provide the

10              most current fund balance sheet for the total fund balance, the calculation of the annual

11              decommissioning expense, the proposed funding term, and any other assumptions

12              supporting ETis calculation.             In response, the Company provided the annual

13              decommissioning revenue requirement based on the Texas retail trust fund liquidation

14              values as of December 31, 2011, the assumed nuclear cost escalation rate of 3.625%

15              agreed to in the settlement of Docket No. 37744, and the projected trust fund earnings

16              rates and the NRC minimum cost estimate utilized in the decommissioning revenue

17              requirement approved in Docket No. 37744.                  This annual revenue requirement is

18              $1,126,000.

     92
          See Order signed 12/13/10 in Docket No. 37744 at paragraph 32, and ETI responses to Cities' 10-20 and 10-22.




     Direct Testimony of Mark E. Garrett                                                          Page 64 of65
     Docket No. 39896
 1   Q:      WHAT IS YOUR RECOMMENDATION WITH RESPECT TO THIS ISSUE?

 2   A:      Chapter 25 of the Substantive Rules Applicable to Electric Providers at §25 .231 (b)(F)(i)

 3           provides that the annual cost of decommissioning for ratemaking purposes must be

 4           determined in each rate case and expressly included in the cost of service established by

 5           the commission's order. The amount expressly established in this case should be the

 6           Company's calculated annual decommissioning revenue requirement of $1,126,000.

 7           Also, an adjustment of $893,000 to the pro forma cost of service is needed to reflect the

 8           difference between the requested level for decommissioning costs of $2,019,000 and

 9           recommended level of $1, 126,000. This adjustment is included at Exhibit MG 2.12.

10

11   Q:      DOES THIS CONCLUDE YOUR TESTIMONY?

12   A:      Yes. It does.




     Direct Testimony of Mark E. Garrett                                           Page 65 of65
     Docket No. 39896
Blank Page
II                                                                II
                    SOAH DOCKET NO. XXX-XX-XXXX
                      PUC DOCKET NO. 39896




     APPLICATION OF ENTERGY TEXAS,    §
     INC. FOR AUTHORITY TO CHANGE     § BEFORE THE STATE OFFICE
     RATES, RECONCILE FUEL COSTS,     §          OF
     AND OBTAIN DEFERRED              § ADMINISTRATIVE HEARINGS
     ACCOUNTING TREATMENT             §




                 DIRECT TESTIMONY AND EXHIBITS

                                OF

                       DR. DENNIS W. GOINS



                          ON BEHALF OF

               CITIES SERVED BY ENTERGY TEXAS, INC.




                          MARCH 27, 2012




                    REDACTED PUBLIC VERSION
Blank Page
                                           TABLE OF CONTENTS


                                                                                                                  Page
INTRODUCTION AND QUALIFICATIONS ..................................................................                   1

CONCLUSIONS •••••••••••••••••••••••••••••••••••.••••••••••••••••..••..•••••.•••••••••••••••••••••...•••••••••••..•••• 4

RECOMMENDATIONS ••••••••••••••••••••••••••••••••••••.••••.•.•.••••••••••••••••••••••••......••••••••...••••••• 8

WHOLESALE JURISDICTION ALLOCATION .••••••••••••••••••••••••••••••••••••••••••••••••••••••••• 10

PURCHASED POWER CAPA CITY COSTS ••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••• 13

MSS-2 COSTS ••••••••••••••••••••••••••••••••••••••.•...••••••••••••••••••..••..•...••.•••••••••••••••••••••••••..... 19

STREET LIGHTING AND TRAFFIC SIGNAL RATES •••••••••••••.•••••••••••......•.•••••••••••••• 21

EXHIBITS

APPENDIX: QUALIFICATIONS




                                                                                     Docket No. 39896
                                                                                     Dennis W. Goins - Direct
                                                                                     Page i
Blank Page
                            SOAH DOCKET NO. XXX-XX-XXXX
                              PUC DOCKET NO. 39896


     APPLICATION OF ENTERGY TEXAS, INC.        §               BEFORE THE
     FOR AUTHORITY TO CHANGE RATES,            §             STATE OFFICE OF
     RECONCILE FUEL COSTS, AND OBTAIN          §          ADlVUNISTRATJVE HEARINGS
     DEFERRED ACCOUNTING                       §




                               DIRECT TESTIMONY OF
                                  DENNIS W. GOINS
                                   ON BEHALF OF
                                      CITIES




                      INTRODUCTION AND QUALIFICATIONS

 2   Q.     PLEASE STATE YOUR NAME, OCCUPATION, AND BUSINESS
 3          ADDRESS.

 4   A.     My name is Dennis W. Goins. I operate Potomac Management Group, an
 5          economics and management consulting firm. My business address is 5801
 6          Westchester Street, Alexandria, Virginia 22310.

 7   Q.     PLEASE         DESCRIBE           YOUR         EDUCATIONAL              AND
 8          PROFESSIONAL BACKGROUND.

 9   A.     I received a Ph.D. degree in economics and a Master of Economics degree
10          from North Carolina State University. I also earned a B.A. degree with
11          honors in economics from Wake Forest University. Following graduate
12          school I worked as a staff economist at the North Carolina Utilities
13          Commission (NCUC).        During my tenure at the NCUC, I testified in
14         numerous cases involving electric, gas, and telephone utilities on such
15          issues as cost of service, rate design, intercorporate transactions, and load
16          forecasting.   While at the NCUC I also served as a member of the
17         Ratcmaking Task Force in the national Electric Utility Rate Design Study

                                                                 Docket No. 39896
                                                                 Dennis W. Goins - Direct
                                                                 Page 1
     sponsored by the Electric Power Research Institute (EPRI) and the
 2   National Association of Regulatory Utility Commissioners (NARUC).
 3      Since leaving the NCUC, I have worked as an economic and
 4   management consultant to firms and organizations in the private and
 5   public sectors.   My assignments focus primarily on market structure,
 6   policy, planning, and pricing issues involving firms that operate in energy
 7   markets. For example, I have conducted detailed analyses of product
 8   pricing, cost of service, rate design, and interutility planning, operations,
 9   and pricing issues; prepared analyses related to utility mergers,
10   transmission access and pricing, and the emergence of competitive
11   markets; evaluated and developed regulatory incentive mechanisms
12   applicable to utility operations; and assisted clients in analyzing and
13   negotiating interchange agreements and power and fuel supply contracts. I
14   have also assisted clients on electric power market restructuring issues in
15   Arkansas, New Jersey, New York, South Carolina, Texas, and Virginia.
16     I have submitted testimony and affidavits and provided technical
17   assistance in nearly 200 proceedings before state and federal agencies as
18   an expert in competitive market issues, regulatory policy, utility planning
19   and operating practices, cost of service, and rate design. These agencies
20   include the Federal Energy Regulatory Commission (FERC), the
21   Government Accountability Office, state courts in Iowa, Montana, and
22   West Virginia, and regulatory agencies in Alabama, Arizona, Arkansas,
23   Colorado, Florida, Georgia, Hawaii, Idaho, Illinois, Indiana, Kansas,
24   Kentucky, Louisiana, Maine, Maryland, Massachusetts, Minnesota,
25   Mississippi, Missouri, New Jersey, New York, North Carolina, Ohio,
26   Oklahoma, South Carolina, Texas, Utah, Vermont, Virginia, West
27   Virginia, Wyoming, and the District of Columbia. Additional details of
28   my educational and professional background are presented in the
29   Appendix.



                                                         Docket No. 39896
                                                         Dennis W. Goins - Direct
                                                         Page 2
     Q.   ON      WHOSE      BEHALF        ARE      YOU     APPEARING          IN    THIS
 2        PROCEEDING?

 3   A.   I am appearing on behalf of the Cities of Anahuac, Beaumont, Bridge City,
 4        Cleveland, Conroe, Dayton, Groves, Houston, Huntsville, Montgomery,
 5        Navasota, Nederland, Oak Ridge North, Orange, Pinc Forest, Pinehurst,
 6        Port Arthur, Port Neches, Rose City, Shenandoah, Silsbee, Sour Lake,
 7        Splendora, Vidor, and West Orange (collectively, the Cities).

 8   Q.   WHAT ASSIGNMENT WERE YOU GIVEN WHEN YOU WERE
 9        RETAINED?

10   A.   I was asked to undertake two primary tasks:
11           1.   Review the application, testimony, and exhibits filed by Entergy
12                Texas, Inc. (ETI) to adjust its base rates, reconcile fuel costs, and
13                obtain deferred accounting. In particular, I was asked to focus on
14                issues related to ETI's proposed treatment of demand-related
15                production costs associated with serving wholesale customers,
16                recovery of purchased power and transmission capacity costs, and
17                the design of street lighting and traffic signal rates.
18           2.   Evaluate the reasonableness of ETI's proposals, and recommend
19                necessary changes.

20   Q.   WHAT INFORMATION DID YOU REVIEW IN CONDUCTING
21        YOUR EVALUATION?

22   A.   I reviewed ETI' s filing, testimony, exhibits, and responses to requests for
23        information. I also reviewed selected testimony and Commission orders in
24        prior ETI rate cases related to issues that I address in my testimony. I also
25        reviewed street lighting and traffic signal rates offered by selected utilities
26        other than ETI.     Finally, I reviewed information found on web sites
27        operated by ETI's parent company, Entergy, Inc., FERC, the Commission,
28        and other selected state regulatory commissions.

                                                                  Docket No. 39896
                                                                  Dennis W. Goins - Direct
                                                                  Page3
                                            CONCLUSIONS

 2   Q.       WHAT CONCLUSIONS HAVE YOU REACHED?

 3   A.       On the basis of my review and evaluation, I have concluded the following:
 4                1.   During the test year in this case (July 20 IO-June 2011 ), ETI
 5                     provided electric service to retail customers in Texas, as well as
 6                     three    wholesale      customers-including          East    Texas     Electric
 7                     Cooperative       (ETEC)-under          service    agreements       and    rates
 8                     approved by FERC. 1 ETEC-a partial requirements customer-
 9                     will be ETI's only wholesale customer during the forward-looking
10                     rate year (June 2012-May 2013).
11                2.   Because ETI does not own sufficient capacity to serve its Texas
12                     retail and ETEC wholesale loads, it must rely on purchased
13                     capacity.     The principal sources of ETI's purchased capacity
14                     resources are:
15                     II   System capacity purchases from EOCs with surplus capacity
16                          that is billed under Service Schedule MSS- I of the Entergy
17                          System Agreement (ESA).               Because Schedule MSS-1 is
18                          designed to share the cost of system reserve capacity among
19                          the EOCs, MSS-1 transactions are referred to as Reserve
20                          Equalization.
21                     11   Unit power purchases from EOCs under Service Schedule
22                          MSS-4 of the ESA. Several of these purchases are related to
23                          purchased power agreements arising from the JSP. 2                     For


     1
       In addition to ETI, the other regulated Entergy Operating Companies (EOCs) are Entergy Gulf
     States Louisiana, LLC (EGSL), Entergy Arkansas, Inc. (EAI), Entergy Louisiana (ELL), Entergy
     Mississippi (EMI), and Entergy New Orleans, Inc. (ENOI). ETI's and EGSL's predecessor was
     Entergy Gulf States, Inc. (EGSI), which was split into two vertically integrated utilities-ETI and
     EGSL-~as a result of the Jurisdictional Separation Plan (JSP) that became effective December 31,
     2007.
     2
       Under the JSP, all of EGSI's transmission and distribution assets and gas-fired generating plants
     were assigned to ETI and EGSL on a situs basis. ETI also got an undivided 42.5-percent share in
     EGSI's 70-percent ownership interest in Nelson 6 and a 42-percent ownership interest in Big


                                                                            Docket No. 39896
                                                                            Dennis W. Goins - Direct
                                                                            Page 4
                            example, as a result of the JSP, ETI has a life-of-unit
 2                          purchased power agreement for 42.5 percent of the 70 percent
 3                          of EGSL's River Bend nuclear station subject to retail
 4                          regulation. ETI refers to these purchases as Legacy Affiliate
 5                          Contracts. In addition, ETI makes unit power purchases from
 6                          EOCs that are unrelated to the JSP.               ETI refers to these
 7                          affiliate purchases as Other Affiliate Contracts 3
 8                    II    Third-party purchases from firms not affiliated with ETI or
 9                          other Entergy companies-for example, ETEC. Two of the
10                          third-party contracts-the 10-year, 485-MW Carville contract
11                          and the 25-year, 225-MW purchase power agreement with
12                          Sam Rayburn Municipal Power Agency (SRMPA)-were not
13                          in place during the test year, but will be in place during the
14                          rate year. 4
15               3.   ETI estimated its cost of servmg Wholesale customers m a
16                    jurisdictional separation study that split ETI' s cost of service
17                    between the Texas Retail and the Wholesale jurisdictions. In this
18                    jurisdictional       study,   ETI    assigned     demand-related        (fixed)
19                    production costs to each jurisdiction using the average and excess,
20                    4 coincident peak (AED4CP) allocation method-the same method
21                    that ETI used in its class cost-of-service study to assign demand-
22                    related production cost responsibility to each retail customer class.
23               4.   ETI (and its predecessors) has historically recovered purchased
24                    power capacity costs in base rates.           However, in this case, ETI
25                    initially proposed recovering $276.2 million in rate year FERC
26                    Account 555 purchased power expense-including MSS-1 and


     Cajun 2, Unit 3---two coal units in Louisiana. EGSL became the owner of EGSI's remaining
     generating plants--including the River Bend nuclear plant.
     3
       See the direct testimony of ETI witness Robert R. Cooper (Cooper Direct) at 21: 1-8 and Exhibit
     RRC-1 (HS). (ETI updated and revised Exhibit RRC-1 (HS) on March 16, 2012.)
     4
       Ibid. at 21 :10-22:14.

                                                                          Docket No. 39896
                                                                          Dennis W. Goins - Direct
                                                                          Page S
                      MSS-4 capacity payments-through a new purchased power
 2                    recovery rider instead of base rates. 5 As a result of a Commission
 3                    ruling following ETI's filing, recovery of ETI's purchased power
 4                     capacity costs (PPCC) is restricted to base rates at present, and
 5                     ETI' s proposed purchased power recovery rider will not be
 6                     considered in this case.
 7               5.    In this case ETI proposed adjusting test-year PPCC to reflect
 8                    known and measurable changes (primarily the expiration of some
 9                    test-year contracts and the commencement of two new purchase
10                    power agreements).         To reflect these changes, ETI recommends
11                    setting its adjusted test-year PPCC equal to its forecast rate year
12                    PPCC ($276.2 million), which will be recovered in base rates.
13                    Including rate-year PPCC in base rates set using historical adjusted
14                    test-year billing determinants ensures overrecovery of ETI's PPCC
15                    if its load grows relative to test-year levels-that is, if rate-year
16                    billing determinants are expected to be greater than test-year billing
17                    determinants. ETI made no adjustment to its rate-year PPCC to
18                    prevent this likely overrecovery.
19               6.   ETI has proposed a similar approach to recover transmission costs
20                    associated with payments under Service Schedule MSS-2.
21                    Specifically, ETI adjusted its test-year MSS-2 costs (approximately
22                    $1.84 million) to reflect a nearly -                  increase in rate-year
23                    MSS-2 costs (almost                                ETI's MSS-2 test-year
24                    adjustment ignores Entergy' s announced divestiture/merger of its
25                    transmission assets into ITC Holdings Corp. (ITC) in 2013.                   In

     5
      On March 16, 2012, ETI updated and revised Exhibit RRC-1 (HS) to reflect the impacts ofrecent
     changes in the EAI WBL contract on ETI's rate-year costs for Other Affiliate Contracts and
     Reserve Equalization. The updated PPCC shown in Exhibit RRC-1 (HS-revised) is $275.8
     million. Because ETI has not yet updated and revised witness Cooper's direct testimony, I use the
     $276.2 million shown in ETI's original filing and Exhibit RRC-1 when referring to ETI's rate-year
     PPCC in my testimony. However, Cities rec01mnended adjustments to ETI's rate-year PPCC that I
     present later include ETI's PPCC adjustments shown in Exhibit RRC-1 (HS-revised).


                                                                          Docket No. 39896
                                                                          Dennis W. Goins - Direct
                                                                          Page 6
          effect, ETI's rate-year estimate assumes that the divestiture/merger
 2        will have no effect on either the level of or method of recovering
 3        (via Schedule MSS-2 of the ESA) such costs.         In addition, ETI
 4        again ignored the effects of load growth when it set rate-year MSS-
 5        2 costs as adjusted test-year MSS-2 costs recovered in base rates.
 6        That is, by ignoring load growth in setting both PPCC and MSS-2
 7        costs that will be recovered in base rates, ETI almost certainly
 8        ensured that it will overrecover both types of costs going forward.
 9   7.   ETI's principal rate schedules for street lighting and traffic signal
10        customers are Schedules SHL and TSS, respectively.          Schedule
11        SHL applies to lighting for public streets, roads, and thoroughfares
12        in cities and in subdivisions with an incorporated homeowners
13        association. Schedule SHL sets fixed monthly charges for standard
14        and nonstandard fixture and lamps that ETI installs and maintains
15        (Rate Groups A and C).       ETI also offers a fixed kWh rate for
16        lighting facilities that the customer owns and maintains (Rate
17        Groups D and E).      Schedule TSS is a fixed kWh rate with a
18        monthly customer charge per delivery point applicable to
19        customer-owned and -maintained traffic signals.      Both proposed
20        rates do not reflect the lower cost of operating and maintaining
21        lighting facilities using energy-efficient light-emitting diode (LED)
22        bulbs.   Moreover, Schedule SHL includes a provision that
23        penalizes a customer that replaces a high-wattage bulb with a more
24        energy-efficient LED bulb.




                                                       Docket No. 39896
                                                       Dennis W. Goins - Direct
                                                       Page 7
                                 RECOMMENDATIONS

 2   Q.   WHAT DO YOU RECOMMEND ON THE BASIS OF THESE
 3        CONCLUSIONS?

 4   A.   I recommend that the Commission take the following actions regarding the
 5        major issues discussed in my testimony:
 6           1.   Reject the AED4CP method used in ETI' s jurisdictional separation
 7                study to assign demand-related production costs to its Texas retail
 8                and wholesale jurisdictions.       Instead, the Commission should
 9                require ETI to assign these costs to the wholesale jurisdiction using
10                the 12 coincident peak (12CP) method to allocate demand-related
11                production costs. This approach is consistent not only with the
12                cost-of-service approach FERC typically uses to allocate demand-
13                related production costs reflected in wholesale rate schedules, but
14                also with the assignment of MSS-1 costs (as well as MSS-2
15                transmission costs) to ETI under the ESA. I have calculated test-
16                year 12CP allocation factors for the Texas Retail (94.6208 percent)
17                and Wholesale (5.3792 percent) jurisdictions, and provided them to
18                Cities witness Karl Nalepa for inclusion in his jurisdictional
19                separation study.
20          2.    Reject ETI's adjusted test-year purchased power capacity costs
21                ($276.2 million). Instead, ETI should be allowed to recover no
22                more than approximately $241.3 million in PPCC.                   This
23                approximately $35 million reduction in ETI's proposed rate-year
24                PPCC estimate reflects the following three adjustments:
25                111   -             reduction in costs for Legacy Affiliate Contracts
26                      to reflect more current pricing data.
27                Ill                  reduction in costs for Other Affiliate Contracts
28                      and Reserve Equalization to reflect more recent contract




                                                                Docket No. 39896
                                                                Dennis W. Goins - Direct
                                                                Page 8
                               pncmg data and Cities recommended adjustment m costs
 2                             related to the EAI WBL contract. 6
 3                    111111                 reduction to reflect the effects of load growth on
 4                             rate-year PPCC costs that ETI will recover going forward.
 5               3.   Reject ETI's adjusted test-year MSS-2 costs. ETI's unexplained
 6                                                     in MSS-2 costs relative to test-year
 7                    costs, plus complete uncertainty regarding the magnitude of ETI's
 8                    post-2012         MSS-2       costs     under      Entergy's       proposed
 9                    divestiture/merger deal with ITC in 2013, make ETI's projected
10                    rate-year MSS-2 costs speculative at best. I recommend setting
11                    ETI's adjusted test-year MSS-2 costs no higher t h a n - -
12                    or
13                    value reflects ETI's actual 2011 MSS-2 costs                          plus a
14                                               to reflect the effects of load growth.
15               4.   Require ETI to modify Schedules SHL (Rate Groups A and C) and
16                    TSS to include a minimum 25 percent reduction in monthly fixed
17                    charges applicable to street and traffic lighting fixtures that use
18                    LED technology. Energy charges in Schedule SHL (Rate Groups
19                    D and E) should also be reduced by 25 percent for LED customers.
20                    This reduction should partially reflect the lower cost of operating
21                    and maintaining energy-efficient LED fixtures.            In addition, the
22                    Commission should require ETI to eliminate the $50 fee applicable
23                    to Rate Groups A and C under Schedule SHL when an existing
24                    light is replaced with a more efficient light with lower wattage (for
25                    example, an LED bulb).           Eliminating this fee will remove a
26                    disincentive for customers to adopt LED fixtures as conservation
27                    measures.


     6
       EAI WBL denotes capacity entitlements in several of EAI's baseload generating units that EAI
     sells at wholesale. Justification for Cities recommended EAI WBL rate-year cost adjustment is
     provided in the direct testimony of Cities witness Karl Nalepa.


                                                                        Docket No. 39896
                                                                        Dennis W. Goins - Direct
                                                                        Page 9
                   WHOLESALE JURISDICTION ALLOCATION

 2   Q.   DID ETI SERVE ANY WHOLESALE CUSTOMERS DURING THE
 3        TEST YEAR?

 4   A.   Yes. ETI provided partial requirements service to 3 wholesale customers
 5        during the test year.   However, during the rate year, ETI projects that
 6        ETEC will be its only partial requirements wholesale customer.

 7   Q.   DOES ETI OWN SUFFICIENT GENERATING CAPACITY TO
 8        SERVE ITS RETAIL AND WHOLESALE CUSTOMERS?

 9   A.   No. ETI is a short EOC-that is, its owned capacity and firm purchases
10        are insufficient to meet its capability responsibility under the ESA. As a
11        result, ETI must rely on additional capacity purchases to meet this
12        shortfall.

13   Q.   IN ITS FILING, DID ETI ESTIMATE ITS COST OF SERVING
14        WHOLESALE CUSTOMERS?

15   A.   Yes. ETI conducted a jurisdictional separation study to determine its cost
16        of serving customers in its Texas Retail and Wholesale jurisdictions. As
17        part of this separation study, ETI used the AED4CP method to allocate
18        demand-related production costs. ETI also used the AED4CP method to
19        allocate demand-related production costs in its retail class cost-of-service
20        study.

21   Q.   IS THE AED4CP THE MOST APPROPRIATE METHOD TO
22        ALLOCATE THESE COSTS BETWEEN JURISDICTIONS?

23   A.   No. In my opinion, the 12CP allocation method would be preferable. The
24        12CP approach is consistent with the cost-of-service approach FERC
25        typically uses to allocate demand-related production costs reflected in
26        wholesale rate schedules. Moreover, the ESA uses a 12CP method to



                                                              Docket No. 39896
                                                              Dennis W. Goins - Direct
                                                              Page 10
          derive each EOC's load responsibility ratio, which is then used to derive
 2        each EOC's share of monthly MSS-1 and MSS-2 charges. Finally, in
 3        reviewing monthly data reflected in ETI's rate-year PPCC shown in
 4        Exhibit RRC-1, I noticed that estimated PPCC by month are relatively
 5        stable-that is, total projected PPCC do not vary significantly by month.
 6        ETI's heavy reliance on capacity purchases to serve load (both retail and
 7        wholesale), and the relative stability of projected monthly PPCC costs
 8        imply that the 12CP method should properly split ETI's demand-related
 9        production costs between the Texas Retail and Wholesale jurisdictions.

10   Q.   IN DOCKET NO. 37744, DID YOU TESTIFY THAT THE AED4CP
11        METHOD WOULD BE REASONABLE TO USE IN ETl'S
12        JURISDICTIONAL SEPARATION STUDY?

13   A.   Yes.   Although I recommended the 12CP method, I noted that the
14        AED4CP method would also be reasonable to use in ETI's jurisdictional
15        separation study.    However, in this case, ETI's reliance on capacity
16        purchases is even greater that it was during test- and rate-years that ETI
17        used in Docket No. 37744. Moreover, in my opinion, for the reasons I
18        cited earlier, the 12CP allocation method is preferable to the AED4CP
19        method proposed by ETI, and should be used to assign ETI' s demand-
20        related production costs to jurisdictions.

21   Q.   DID YOU CALCULATE JURISDICTIONAL 12CP ALLOCATION
22        FACTORS IN THIS CASE?

23   A.   Yes. I calculated test-year 12CP allocation factors for the Texas Retail
24        and Wholesale jurisdictions. I provided the 12CP factors to Cities witness
25        Karl Nalepa for inclusion in his jurisdictional separation study. As shown
26        in Exhibit DWG-1 and Table 1 below, the 12CP allocation factor for the
27        Wholesale jurisdiction is about 5.38 percent versus 4.62 percent under
28        ETI' s recommended AED4CP method.


                                                             Docket No. 39896
                                                             Dennis W. Goins - Direct
                                                             Page 11
            Table 1. Jurisdictional Separation

                                Demand-Related Production
                                  Cost Allocation Factor
            Jurisdiction         AED4CP                 12CP

            TX Retail              95.3838%             94.6208%

            Wholesale               4.6162%             5.3792%

              Total               100.0000%         100.0000%

            Source: Schedule P-7.2 and Exhibit DWG-1.




 2   Q.   WHAT LOADS DID YOU USE IN CALCULATING THE 12CP
 3        WHOLESALE ALLOCATION FACTOR THAT YOU PROVIDED
 4        WITNESS          NALEPA      FOR     USE       IN    HIS    JURISDICTIONAL
 5        SEPARATION ANALYSIS?

 6   A.   I used a loss-adjusted 150 MW (ETEC's monthly billing MW) as a proxy
 7        for the 12 monthly CPs. The 150 MW is indicative of ETI's capacity
 8        obligations to ETEC, and reflects known and measurable changes
 9        compared to test-year wholesale CPs (which would include CPs for
10        wholesale customers that ETI no longer serves).

11   Q.   SHOULD THE COMMISSION REQUIRE ETI TO USE THE 12CP
12        METHOD           TO   ASSIGN        DEMAND-RELATED               PRODUCTION
13        COSTS TO JURISDICTIONS?

14   A.   Yes.   The l 2CP method best reflects how ETI incurs demand-related
15        production costs to serve Texas Retail and Wholesale customers.




                                                                     Docket No. 39896
                                                                     Dennis W. Goins - Direct
                                                                     Page 12
                             PURCHASED POWER CAPACITY COSTS

 2   Q.      DOES            ETI    CURRENTLY           HAVE     ENOUGH         CAPACITY
 3           RESOURCES TO SERVE ITS RETAIL AND WHOLESALE
 4           CUSTOMERS?

 5   A.      No. Under Schedule MSS-1, an EOC with fewer capacity resources than
 6           its capacity responsibility must buy capacity from other EOCs whose
 7           capacity resources exceed their capacity obligations. This capacity deficit
 8           situation is commonly referred to as a short position, in contrast to a long
 9           position involving a capacity surplus.          Even with major increases in
10           purchased capacity, ETI expects to be short more than -               during the
11           rate year. 7

12   Q.      WHAT TYPES OF PURCHASES DOES ETI PLAN TO USE TO
13           MEET THIS CAPACITY SHORTFALL?

14   A.      ETI plans to use four principal categories of purchases:
15                    1111    Schedule MSS-1 purchases (Reserve Equalization) from other
16                            EOCs with surplus capacity.
17                    1111    Schedule MSS-4 purchases related to purchased power
18                            agreements arising from the JSP (Legacy Affiliate Contracts).
19                    1111    Schedule MSS-4 unit power purchases unrelated to the JSP
20                            (Other Affiliate Contracts).
21                    1111    Third-party purchases from companies not affiliated with ETI
22                            or other Entergy companies.
23           ETI witness Robert R. Cooper discusses these categories of purchases in
24           his direct testimony, and presents rate-year estimates of ETI' s purchases in
25           each category in Exhibit RRC-1 (Highly Sensitive).




     7
      See ETI's responses to Cities 2-1.d (RRC-1 Workpaper   MSS-1 111215_HSPM) and TIEC 1-
     17 (HS).


                                                                     Docket No. 39896
                                                                     Dennis W. Goins - Direct
                                                                     Page 13
     Q.         ARE ETI'S RA TE-YEAR PPCC SIGNIFICANTLY HIGHER THAN
 2              ITS TEST-YEAR PPCC?

 3   A.         Yes. ETI's projected rate-year PPCC ($276.2 million) exceed test-year
 4              PPCC by a b o u t - . My review of these costs indicates that third-
 5              party purchases are the principal driver of the increase-growing more
 6              than -               from                   to

 7   Q.         HOW HAS ETI TRADITIONALLY RECOVERED PURCHASED
 8              POWER CAPACITY COSTS?

 9   A.         ETI has traditionally recovered these costs in base rates smce the
10              Commission's current fuel rule excludes purchased power demand or
11              capacity costs from eligible and reconcilable fuel expenses absent a
12              finding of special circumstances. 9

13   Q.         IN THIS CASE, DID ETI INITIALLY PROPOSE TO CONTINUE
14              RECOVERING PPCC IN BASE RATES?

15   A.         No. ETI proposed recovering PPCC in a purchased power recovery rider.
16              However, the Commission issued a ruling indicating that ETI's proposed
17              rider would not be considered in this case because of the ongoing
18              rulemaking in Project No. 39246 to consider the issue of how PPCC
19              should be recovered.         As a result, ETI will continue to recover PPCC
20              approved by the Commission in base rates.

21   Q.         WHY IS IT IMPORTANT TO ENSURE THAT THE LEVEL OF
22              PPCC INCLUDED IN BASE RATES IS REASONABLE AND NOT
23              SIGNIFICANTLY OVERSTATED?

24   A.         Purchased power capacity costs included in base rates are not subject to
25              true-up and reconciliation. If the level of PPCC included in base rates is

     8
         See ETI's response to Cities 2-1.a.iii-iv (including Addendum 1).
     9
         PUC Subst. R. 25.236(a)(4).


                                                                             Docket No. 39896
                                                                             Dennis W. Goins - Direct
                                                                             Page 14
          significantly overstated, ratepayers will simply pay for costs that ETI never
 2        incurs. The level of PPCC included in base rates must strike a balance
 3        between giving ETI a reasonable opportunity to recover prudent capacity
 4        costs that it incurs going forward, and protecting ratepayers from giving a
 5        windfall to ETI.

 6   Q.   DID ETI ADJUST ITS TEST-YEAR PPCC?

 7   A.   Yes.     ETI recommends adjusting test-year PPCC for known and
 8        measurable changes (including the expiration of some test-year contracts
 9        and the start of two new post-test-year purchase power agreements). To
10        reflect these changes, ETI set adjusted test-year PPCC equal to rate-year
11        PPCC ($276.2 million).

12   Q.   DOES          ETl'S    ADJUSTED      TEST-YEAR        PPCC     RAISE      ANY
13        CONCERNS?

14   A.   Yes. ETI's estimate raises two major concerns:
15               1111     ETI did not modify the level of adjusted test-year PPCC it
16                        proposes to include in base rates for the going-forward effects
17                        of load growth on PPCC recovery. This oversight ensures that
18                        ETI will overrecover its adjusted test-year PPCC if load
19                        growth results in base rate billing determinants greater than
20                       test-year billing determinants used to set base rates in this
21                       case.
22               1111    ETI developed rate-year cost estimates for Legacy Affiliate
23                       and Other Affiliate transactions using the September 2010-
24                       August 2011 average cost per MW for each affiliate contract.
25                       More recent average cost (price proxy) data for ETI's affiliate
26                       transactions are available, and should be used to reflect known
27                       and measurable cost changes.




                                                                 Docket No. 39896
                                                                 Dennis W. Goins - Direct
                                                                 Page 15
     Q.   PLEASE EXPLAIN THE LOAD GROWTH ISSUE AND WHY IT
 2        SHOULD BE REFLECTED IN THE LEVEL OF PPCC INCLUDED
 3        IN BASE RATES IN THIS CASE.

 4   A.   A simple example illustrates the problem. Assume Utility X files a rate
 5        case in which its test-year billing units and PPCC are 100 units and $500,
 6        respectively (see Table 2 below). Also assume that Utility X's projected
 7        rate-year PPCC is $1,000, which it asks the regulator to include in base
 8        rates set in the current rate case instead of $500 in test-year PPCC that
 9        Utility X actually incurred. Finally, assume the regulator allows Utility X
10        to include rate-year PPCC in base rates instead of test-year PPCC. As a
11        result, the level of PPCC included in base rates set in the current rate case
12        is $10 per billing unit (that is, $1,000 in rate-year PPCC, divided by 100
13        test-year billing units).
14           Now move forward to the rate year when rates set in the rate case are in
15        effect. Assume that Utility X was correct in the rate case-its rate-year
16        PPCC turns out to be $1,000 exactly as it had projected. However, Utility
17        X's rate-year billing units have grown to 200 units-not 100 units that it
18        sold in the test year. As a result of this load growth, Utility X will recover
19        $2,000 of PPCC during the rate year ($10 per billing unit in base rates,
20        times 200 rate-year billing units)-or twice the level of PPCC that it
21        actually incurs in the rate year, and twice the amount the regulator
22        assumed would occur when approving base rates in the rate case to recover
23        projected rate-year PPCC.




                                                               Docket No. 39896
                                                               Dennis W. Goins - Direct
                                                               Page 16
                  Table 2. Effect of Load Growth on PPCC Recovery


                   Line                   Item              Test Yr Rate Yr                  Comment

                    1     Billing Units                        100     200

                    2     Actual PPCC                        $500

                    3     Projected PPCC                             $1,000

                    4     Base Rate PPCC                    $1,000            Rate-Yr PPCC included in Base Rates

                    5     PPCC/Billing Unit in Base Rates      $10            Line 4 I 100 Test-Yr billing units

                    6     Actual PPCC Recovered                      $2,000   Line 5 * 200 Rate-Yr billing units



 2                  ETI's proposed adjusted test-year PPCC creates the same problem,
 3               because ETI is implicitly asking the Commission to ignore load growth
 4               and set base rates in this case using rate-year PPCC and test-year billing
 5              units. Using test-year billing determinants to set rates to recover ETI's
 6               rate-year PPCC guarantees that ETI will overrecover its estimated rate-
 7              year PPCC if rate-year billing units exceed test-year billing units-that is,
 8              if ETI' s load grows.

 9   Q.         DOES ETI EXPECT ITS LOAD TO GROW FROM THE TEST
10              YEAR THROUGH THE RATE YEAR?

11   A.         Yes. ETI expects a steady growth in both energy sales and peak load in
12              the next few years. 10

13   Q.         HA VE YOU MODIFIED ETI'S ESTIMATED RA TE-YEAR PPCC
14              TO REFLECT YOUR CONCERNS REGARDING THE LOAD
15              GROWTH AND AFFILIATE TRANSACTION PRICING ISSUES?

16   A.         Yes.      I first adjusted the average cost per MW (proxy price) used to
17              develop the rate-year cost of Legacy Affiliate and Other Affiliate
18              (excluding EAI WBL) transactions. Specifically, I used transaction cost
19              data from November 2010-0ctobcr 2011 (instead of September 2010-
20              August 2010 data that ETI used) to develop the transaction proxy prices

     10
          See ETI's response to Cities 2-2 (HS).


                                                                                      Docket No. 39896
                                                                                      Dennis W. Goins - Direct
                                                                                      Page 17
              and rate-year costs. Next, I adjusted ETI's rate-year estimates of costs for
 2            the EAI WBL contract and Reserve Equalization to reflect the adjustment
 3            recommended by Cities witness Karl Nalepa. Finally, I adjusted the rate-
 4           year total PPCC estimate to reflect the effects of load growth.                    The
 5            resulting adjusted test-year PPCC by transaction category is shown in
 6           Exhibit DWG-2. 11        As shown in this exhibit, ETI's adjusted test-year
 7           PPCC should be set no higher than $241.3 million-or $35 million less
 8           than ETI's original request. As I noted earlier, this $35 million reduction
 9           in ETI's proposed rate-year PPCC estimate reflects the following three
10           adjustments:
11                    II   -               reduction in costs for Legacy Affiliate Contracts
12                         to reflect more current pricing data.
13                    II                     reduction in costs for Other Affiliate Contracts
14                         and Reserve Equalization to reflect more recent contract
15                         pricing data and Cities recommended adjustment in costs
16                         related to the Cities recommended SO-percent reduction m
17                         adjusted test-year costs for the EAI WBL contract.
18                    II                    reduction to reflect the effects of load growth.

19   Q.      HOW DID YOU DEVELOP THE LOAD GROWTH ADJUSTMENT
20           YOU APPLIED TO YOUR PPCC ESTIMATE?

21   A.      The development of my recommended                                       load growth
22           adjustment is presented in Exhibit DWG-3. I first reviewed forecasts of
23           ETI's firm load (energy sales and peak demand) from 2011 through 2014.
24           I then calculated the growth in ETI' s energy sales and peak demands over
25           different intervals (Exhibit DWG-3, page 1). On the basis of this review, I
26           s e l e c t e d - as a reasonable estimate of the likely growth in ETI's
27           energy and demand billing determinants from the test year to the rate year.

     11
       Results shown in Exhibit DWG-2 are presented in a format similar to that used by ETI's witness
     Robert Cooper in Exhibit RRC-1 (HS-revised).


                                                                          Docket No. 39896
                                                                          Dennis W. Goins - Direct
                                                                          Page 18
          I next estimated ETT's rate-year energy billing units, and derived an
 2        average cost per billing unit (Exhibit DWG-3, page 2) for the estimated
 3        rate-year PPCC shown in column (c) of Exhibit DWG-2. The product of
 4        this average rate-year PPCC and ETI's test-year kWh billing units equals
 5        the adjusted test-year PPCC that ETI should be allowed to include in base
 6        rates.

 7   Q.   IS YOUR RECOMMENDED $241.3 MILLION IN ADJUSTED
 8        TEST-YEAR PPCC A REASONABLE AND FAIR ESTIMATE OF
 9        COSTS THAT ETI IS LIKELY TO INCUR IN THE RATE YEAR?

10   A.   Yes. My estimate mitigates two problems that cause ETI to overstate its
11        rate-year PPCC-its failure to adjust rate-year projections to reflect load
12        growth, and the use of dated transaction price proxies. In addition, my
13        estimate reflects witness Nalepa's recommended cost adjustments related
14        to the EAI WBL contract.


15                                   MSS-2 COSTS

16   Q.   WHAT ARE MSS-2 COSTS?

17   A.   Under the ESA's Service Schedule MSS-2, the EOCs share cost
18        responsibility for the Entergy transmission system much like they share
19        cost responsibility for generating resources under Service Schedule MSS-
20        1. Each month an EOC receives a payment or bill for System transmission
21        costs based on the EOC's level of transmission investment relative to total
22        System transmission investments, its load responsibility ratio, and the
23        average cost of total System investments.




                                                             Docket No. 39896
                                                             Dennis W. Goins - Direct
                                                             Page 19
     Q.   WHAT LEVEL OF MSS-2 COSTS HAS ETI PROPOSED TO
 2        INCLUDE IN BASE RATES IN THIS CASE?

 3   A.   ETI has proposed including almost                 of rate-year MSS-2 costs
 4        in base rates.

 5   Q.   IS ETI'S PROPOSED LEVEL OF MSS-2 COSTS SIGNIFICANTLY
 6        GREATER THAN ITS TEST-YEAR MSS-2 COSTS?

 7   A.   Yes. ETI' s projected rate-year MSS-2 costs                   are more than
 8                            actual test-year MSS-2 costs ($1.8 million).

 9   Q.   DID ETI PROVIDE DETAILS REGARDING WHY ITS RATE-
10        YEAR MSS-2 COSTS ARE EXPECTED TO GROW SO MUCH?

11   A.   No.    ETI provided workpapers supporting its rate-year MSS-2 cost
12        projection, 12 but did not provide details explaining the
13


14   Q.   DID ETI ADJUST ITS PROJECTED RA TE-YEAR MSS-2 COSTS
15        TO REFLECT CHANGES IN BILLING AND TRANSMISSION
16        INVESTMENTS           THAT        MAY         ARISE         WHEN      THE
17        DIVESTITURE/MERGER              OF    ENTERGY'S        TRANSMISSION
18        ASSETS INTO ITC IS COMPLETED IN 2013?

19   A.   No. ETI's MSS-2 cost projections assume business-as-usual even though
20        Entergy will no longer be sole owner of transmission assets used to deliver
21        power and energy to its EOCs following the proposed divestiture/merger.
22        This calls into question the future applicability of Service Schedule MSS-2
23        to the EOCs, and the reasonableness of ETI's MSS-2 rate-year
24        projection-a conclusion indirectly supported by ETI.         For example,
25        during his deposition, ETI witness Phillip May acknowledged that if the
26        divestiture/merger takes place as planned, ETI's MSS-2 costs would be



                                                             Docket No. 39896
                                                             Dennis W. Goins - Direct
                                                             Page 20
                 zero. 13 In general, the pending divestiture/merger makes ETI's MSS-2 cost
 2               projections problematic.

 3   Q.          IS THERE AN ADDITIONAL PROBLEM WITH ETI'S ADJUSTED
 4               TEST-YEAR MSS-2 COSTS?

 5   A.          Ycs. Including ETI's MSS-2 rate-year costs in base rates creates the same
 6               problem that I discussed with respect to ETI's rate-year PPCC.
 7               Specifically, using base rates that reflect test-year billing determinants to
 8               recover projected rate-year MSS-2 costs guarantees ovcrrecovery if rate-
 9               year billing units exceed test-year billing units-that is, if ETI's load
10               grows.

11   Q.          HOW SHOULD ETl'S RATE-YEAR MSS-2 COSTS BE ADJUSTED
12               TO ADDRESS THESE ISSUES?

13   A.          I recommend a 2-step approach:
14                        II   Because of the pending divestiture/merger of Entergy' s
15                             transmission assets, limit MSS-2 costs included in base rates
16                             to no more than actual MSS-2 costs incurred in the most
17                             recent 12 months.           This modification also addresses the
18                                                                        of ETI's MSS-2 costs.
19                        II   Adjust the modified post-test year MSS-2 cost estimate for
20                             load growth in a manner similar to the approach I used in
21                             adjusting rate-year purchased power capacity costs.




     12
          See ETI's response to Cities 5-3.a.
     13
          See the transcript of the March 6, 2012, deposition of ETI witness Phillip R. May at 43: 10.


                                                                                Docket No. 39896
                                                                                Dennis W. Goins - Direct
                                                                                Page 21
     Q.   HA VE      YOU      DEVELOPED          AN     ADJUSTED          TEST-YEAR
 2        ESTIMATE OF MSS-2 COSTS THAT SHOULD BE INCLUDED IN
 3        BASE RATES?

 4   A.   Yes. As shown in Exhibit DWG-4, the level of adjusted test-year MSS-2
 5        costs included in base rates should not exceed $4.1 million. This value
 6        reflects ETI's actual annual MSS-2 costs through December 2011, and a
 7        load growth adjustment.


 8                           STREET LIGHTING AND
 9                           TRAFFIC SIGNAL RATES

10   Q.   DID YOU REVIEW ETI'S STREET LIGHTING AND TRAFFIC
11        SIGNAL RATES?

12   A.   Yes.    ETI's principal rate schedule for street lighting customers is
13        Schedule SHL, while Schedule TSS is the principal rate schedule for ETI's
14        traffic lighting customers that own and maintain their lighting facilities.

15   Q.   IS SERVICE UNDER SCHEDULE SHL UNIFORM FOR ALL
16        STREET LIGHTING CUSTOMERS?

17   A.   No. The rate includes four categories of service (Rate Groups A, C, D,
18        and E). Rate Group A includes ETI's standard fixture and lamps mounted
19        on existing standard wood poles that ETI installs and maintains.          If a
20        customer wants nonstandard lighting facilities (those not provided in Rate
21        Group A), the customer is assigned to Rate Group C and required to
22        prepay ETI for the incremental cost of the nonstandard facilities. Lighting
23        facilities that are customer-owned and customer-maintained are assigned
24        to Rate Group D, while incidental lighting services (for example,
25        underpass lighting) are assigned to Rate Group E.




                                                                Docket No. 39896
                                                                Dennis W. Goins - Direct
                                                                Page 22
     Q.   DO    CHARGES        VARY        BY   CATEGORY           OF   SERVICE        IN
 2        SCHEDULE SHL?

 3   A.   Yes. Customers in Rate Groups A and C pay a fixed monthly charge per
 4        lighting fixture, while customers in Rate Groups D and E pay a fixed (and
 5        identical) energy charge per kWh.       Each customer's monthly bill also
 6        includes charges for ETI's fixed fuel factor (Schedule FF) and applicable
 7        riders applied to monthly kWh per fixture.

 8   Q.   WHAT TYPES OF CHARGES ARE APPLICABLE UNDER
 9        SCHEDULE TSS?

10   A.   Traffic signal customers pay a fixed monthly charge ($3 .20 proposed) per
11        point of delivery, plus a fixed kWh rate and all applicable rider charges.

12   Q.   DO ETI'S LIGHTING RATES INCORPORATE ANY SPECIAL
13        SERVICE OR PRICING PROVISIONS FOR NEW ENERGY-
14        EFFICIENT       LIGHTING         TECHNOLOGIES-FOR              EXAMPLE,
15        LED FIXTURES?

16   A.   No. The basic structure and pricing provisions of the SHL and TSS rates
17        have been in place for years. The rates were designed for lighting fixtures
18        that use older, less energy-efficient bulb technology.

19   Q.   DID    ETI    CONDUCT A           DETAILED       COST ANALYSIS               IN
20        DEVELOPING PROPOSED CHARGES FOR STREET LIGHTING
21        AND TRAFFIC SIGNAL CUSTOMERS?

22   A.   I have seen no evidence that ETI conducted such an analysis. Moreover,
23        in this case, ETI did not conduct any analyses to estimate the cost
24        differential of serving street lighting and traffic signal customers that use
25        energy-efficient LED fixtures.




                                                               Docket No. 39896
                                                               Dennis W. Goins - Direct
                                                               Page 23
     Q.   HOW DID ETI ADJUST PROPOSED PRICES IN ITS LIGHTING
 2        RATES IN THIS CASE?

 3   A.   ETI applied a unifonn percentage increase to the kWh and fixed charges in
 4        Schedule SHL. In Schedule TSS, ETI left the fixed monthly charge per
 5        delivery point unchanged, but reduced the kWh charge to reflect its
 6        proposal to recover PPCC through a rider. (This latter change will be
 7        reversed to reflect the Commission's ruling in this case regarding recovery
 8        of PPCC in base rates.)

 9   Q.   WHY ARE LED FIXTURES AN ATTRACTIVE LIGHTING
10        OPTION FOR MUNICIPALITIES?

11   A.   The cost of street and traffic lighting services can be significant for many
12        cities and towns.   As government agencies face increasing pressure to
13        control budgets, municipalities are increasingly looking at energy-efficient
14        lighting options such as LED fixtures to provide an ongoing, long-term
15        reduction in operating costs. LED fixtures use significantly less energy
16        than incandescent and most other lighting options, last longer, and may
17        require less maintenance (for example, fewer bulb replacements).

18   Q.   HA VE ANY OF THE CITIES ADOPTED LED LIGHTING AS A
19        WAY TO REDUCE THEIR OPERATING COSTS?

20   A.   Yes.   Counsel has informed me that at least one of the Cities has an
21        ongoing program to replace incandescent fixtures with LED options, and
22        several others are actively considering moving to LED lighting.

23   Q.   WOULD WIDESPREAD ADOPTION OF LED LIGHTING RATES
24        HELP REDUCE ENERGY CONSUMPTION IN TEXAS?

25   A.   Yes. Such rates would encourage municipalities to adopt energy-efficient
26        LED options, and help offset the high front-end cost of LED lights.



                                                              Docket No. 39896
                                                              Dennis W. Goins - Direct
                                                              Page 24
     Q.   HAVE MOST UTILITIES IMPLEMENTED LIGHTING RATES
 2        THAT REFLECT THE LOWER COST OF OPERATING LED
 3        FIXTURES?

 4   A.   No. I reviewed street lighting and traffic signal rates offered by a number
 5        of utilities. Although some of them have implemented LED rates, most
 6        utilities have not updated their rates to reflect the lower operating and
 7        maintenance cost of serving energy-efficient LED fixtures.

 8   Q.   DOES ANY UTILITY IN TEXAS HAVE AN LED LIGHTING
 9        OPTION?

10   A.   Yes. In 2010 the Commission approved a street and traffic signal rate for
11        El Paso Electric (Docket No. 37690) that included separate charges for
12        LED traffic signals. (See Exhibit DWG-5.) The fixed monthly rate for
13        LED signals is generally less than one-third the comparable rate for
14        incandescent signals.

15   Q.   SHOULD THE COMMISSION REQUIRE ETI TO INCLUDE AN
16        LED OPTION IN ITS SHL AND TSS RATES?

17   A.   Yes. ETI should offer an LED option in these rates to encourage energy
18        efficiency investments and promote conservation.       To facilitate these
19        goals, the Commission should require ETI to modify monthly fixed
20        charges in Schedule SHL (Rate Groups A and C) and TSS to reflect a 25-
21        percent discount for LED installations.   The discounted Rate Group A
22        fixed charges (if applicable) in Schedule SHL should be applied according
23        to the estimated monthly kWh consumption of the installed LED fixture.
24        In addition, I recommended reducing by 25 percent the Schedule SHL
25        kWh charges applicable to LED customers assigned to Rate Groups D and
26        E to reflect the lower cost of operating and maintaining LED fixtures. In
27        the future, ETI should be required to provide detailed information



                                                             Docket No. 39896
                                                             Dennis W. Goins - Direct
                                                             Page 25
          regarding differences in the cost of serving LED and non-LED lighting
 2        customers.

 3   Q.   HAVE YOU IDENTIFIED ANY                  OTHER CHANGES THAT
 4        SHOULD BE MADE IN ETl'S PROPOSED LIGHTING RATES?

 5   A.   Yes.   The Commission should require ETI to eliminate the service
 6        condition applicable to Rate Groups A and C in Schedule SHL that
 7        charges a $50 fee for any replacement of a functioning light with a lower-
 8        wattage bulb. This fee actively discourages customers from adopting more
 9        energy-efficient lighting technologies (for example, LED devices), and is
10        not supported in ETI' s filing.   The Commission should get rid of this
11        barrier to conservation and efficiency improvements.

12   Q.   DOES THIS COMPLETE YOUR DIRECT TESTIMONY?

13   A.   Yes.




                                                            Docket No. 39896
                                                            Dennis W. Goins - Direct
                                                            Page 26
                                                                   Exhibit DWG-1
                                                                   Page 1 of 1




Jurisdictional Separation: Demand-Related Production Costs - 12CP


                                     12CP kW          12CP
       Class of Service               at Plant        Factor
              (a)                        (b)            (c)

Residential                         1,240,632        43.4768%
Small General Service                  57,554         2.0169%
General Service                       531, 108       18.6122%
Large General Service                 212, 129        7.4339%
Large Industrial Power Service        654,652        22.9417%
Roadway Lighting                        1,633         0.0572%
Non-Roadway Lighting                    2,345         0.0822%
  Total Texas Retail                2,700,053        94.6208%

Wholesale For Resale                   153,498        5.3792%
Wheeling                                     0        0.0000%
 Total Texas Wholesale                 153,498        5.3792%

Total ETI                           2,853,551       100.0000%



Source: Schedule P-7.2, pages 21-22, and ETl's response to TIEC 1-38 Highly Sensitive.
Blank Page
Exhibit DWG-2
Redacted

Highly Sensitive
Blank Page
Exhibit DWG-3
Redacted

Highly Sensitive
Blank Page
Exhibit DWG-4
Redacted

Highly Sensitive
Blank Page
                                                          EXHIBIT DWG-5




EL PASO ELECTRIC'S SCHEDULE NO.   08- GOVERNMENT STREET
LIGHTING AND SIGNAL SERVICE RATE
Blank Page
                                        EL PASO ELECTRIC COMPANY

                                            SCHEDULE NO. 08
                                     GOVERNMENTAL STREET LIGHTING
                                        AND SIGNAL SERVICE RATE

    APPLICABILITY

   This rate is availabie to any village, town, city, county, state of Texas and Federal
   facilities for Mercury Vapor and High Pressure Sodium Vapor street light, freeway lighting
   and for traffic signal lights.

   TERRITORY

   Texas Service Area

   MONTHLY RATE

   Street Lights

                  MERCURY VAPOR-OVERHEAD SYSTEM-COMPANY OWNED
                        35 FOOT MOUNTING HEIGHT - WOOD POLE ·k
                                                                -
                                                                             Total     Per Lamp
                                                                            Wattage     Charge
   175W - 7,000 Lumen Single
,__________~-·
                                                                              195       $15.22
   250W - 11,000 Lumen Single                                                 275       $18.26
                                                        -
   400W - 20,000 Lumen Single                                                 460       $21.66
   400W - 20,000 Lumen Double                                                 920       $35.i9


     HIGH PRESSURE SODIUM VAPOR - DOWNTOWN EL PASO AREA- COMPANY
                  OWNED STEEL BASE STANDARD AND LUM1NA1RE
                                                        Total  Per Lamp
                                                       Wattage  Charge
  1,000W -119,500 Lumen Overhead System                 1,102   $54.81
  1,000W - 119,500 Lumen Underground System             1,102   $89.45


    H1GH PRESSURE SODIUM VAPOR- DOWNTOWN EL PASO AREA- COMPANY
                  OWNED STEEL BASE STANDARD AND LUM!NAIRE
                                                        Total  Per Lamp
                                                       Wattage  Charge
  450W - 50,000 Lumen Overhead System                   485     $47.87

    * Refer to Mercury Vapor Closed to New Installations and Conversiin/Replacement of
        Existing Installations section of the tariff.                     • UB!.IC UTILITY COMMISSION Of TEXAS
        . . ··     . ···                                                                APPROVED

                                                                         JUL 3D'10     DOCKET

                                                                           CONTROL#.
  Section Number_ _ __,_1_ _ _ __                           Revision Number             20  ----
  SheetNumber~~~--'-7-~~~­                                  Effective for consumQt!on on or
  Page~~~-~~-l~o_f~8~~~-                                               after July 1, 2010
                                 El PASO ELECTRIC COMPANY

                                     SCHEDULE NO. 08
                              GOVERNMENTAL STREET LIGHTING
                                 AND SIGNAL SERVICE RATE

               MERCURY VAPOR - OVERHEAD SYSTEM - COMPANY OWNED
                      30 FOOT MOUNTING HEIGHT-STEEL POLE*
                                                          Total Per Lamp
~·
                                                        Wattage  Charge
     400W - 20,000 Lumen Single                           460    $33.46
     400W - 20,000 Lumen Double                           920    $46.99


                MERCURY VAPOR - NON-COMPANY OWNED SYSTEMS
                  -
                       INTERSTATE OR FREEWAY LIGHTING*
                                                              Total                        Per Lamp
                                                             Wattage                        Charge
 250W - i 1,000 Lumen - Wall Mounted                           292                              $8.78
 400W - 20,000 Lumen - 40 Foot Maximum Mounting Height         460                             $12.08
 1_,000W - 60,000 Lumen - 50 Foot Maximum Mounting Heigb_t__  1, 102                          $31.67


            MERCURY VAPOR - NON-COMPANY OWNED - WOOD POLE
             UNDERGROUND OR OVERHEAD RESIDENTIAL SERViCE "
                                                      --
                                                          Total                            Per Lamp
                                                         Wattaoe                            Charqe
 175W - 7,000 Lumen - 35 Foot Maximum Mounting Height      195                              $6.68

     * Refer to Mercury Vapor Closed to New Installations and Conversion/Replacement of
       Existing Installations section of the tariff.


         HIGH PRESSURE SODIUM VAPOR - NON-COMPANY OWNED SYSTEMS
                          INTERSTATE   OR FREEWAY LIGHTING
                            -
                                                                  Total        Per Lamp
                                                                Wattaqe         Charqe
 150W - 16,000 Lumen - Wall Mounted                                193            $7.00
 250W - 23,200 Lumen - Waif ~ounted                                313            $9.42
 250W • 23,200 Lumen - 40 Foot Maximum Mountinq Heiqht             313            $9.42
 400'{1! - 50,000 Lumen - 50 Foot Maximum MountinQ Heiqht          485          $12.95
 400W - 50,000 Lumen - Tower Structure 150 Foot-Climbing           485          $13.67
 Maximum Mounting Height
 10 Luminaires per Tower                                  PUB' !C UTiLJTY Cb;\:'.\ 1'.~S'.SlGN C , TEX.AS
                                                                       P~Ff ';1
 Rate per fixture
                                                                   JUL 3 o~rn     [)( f:'/'.7
                                                                                      ..._~n; .. l   'Z 7
                                                                                                     ;.JI   690
                                                                      CONTflOLil

 Section Number 1  ~~~---~~~~
                                                      Revision Number              20
                                                                        ~~-------=--~~~~-

 Sheet Number   7~~~~~~~~~
                                                      Effective for consumption on or
 Page~~~~~~=2~o~f8,,,__~~~-                                      after July 1, 201 O
                            EL PASO ELECTRIC COMPANY

                                SCHEDULE NO. 08
                         GOVERNMENTAL STREET LIGHTING
                            AND SIGNAL SERVICE RATE

 400W - 50,000 Lumen - Tower Structure 150 Foot-Lowering           485         $12.79
 Maximum Mounting Height
 10 Luminaires per Tower
 Rate per fixture
>----                                                                      -
 116W - Obstruction Lights Incandescent 40 Foot Maximum            116          $4.47
 Mounting Height
 116W -150 Foot Tower                                             ..116         $5.35


      HIGH PRESSURE SODIUM VAPOR-NON-COMPANY OWNED SYSTEMS
                           LARGE ARTERIAL LIGHTING
                                                    Total  Per Lamp
                                                   Wattage  Charg~
 150W-16,000 Lumen Wall Mounted                      193     $7.11
 250W - 23,?00 Lumen Wall Mounted                   313     $10.24
 250W -23,200 Lumen 40 FT Maximum Mounting Height   313     $10.24
~OW - 50,000 Lumen 50 FT Maximum Mounting Height    485     $14.73


             HIGH PRESSURE SODIUM VAPOR - NON-COMPANY OWNED
         WOOD/STEEL POLE UG OR OH STANDARD RESIDENTIAL SERVICE
                                                        Total  Per Lamp
                                                       Wattage   Charge
 1 OOW - 8,500 Lumen - 30 Foot Maximum Mounting Height   124   -
                                                                  $5.32
 150W - 14,400 Lumen - 30 Foot Maximum Mounting Height   193      $6.21
 250W - 23,200 Lumen - 30 Foot Maximum Mounting Height  313       $9.59


       HIGH PRESSURE SODIUM VAPOR - OVERHEAD - NON-COMPANY OWNED
                 FIXTURE- COMPANY OWNED EXISTING WOOD POLE
                      (DISTRIBUTION OR STREET LIGHT CF or Dl
                                                              Total  Per Lamp
                                                             WattaQe  Charge
  1 OOW - 8,500 Lumen - 35 Foot Maximum Mounting Heii:iht      124     $7.43
· 150W - 14~190 Lumen - 35 Foot Maximum Mounting Height        193     $8.99
  250W - 23,200 Lumen - 35 Foot Maximum Mounting Height       313     $11.41
  250W - 23,200 Lumen - Double 35 Foot Maximum Mounting       626     $18.65
  Heiqht
  450W - 50,QOO Lumen - 50 Foot Maximum Mounting Height       485     $14.06




                                                                                        37690
 Section Number     1
               ~~~~~~~~-
                                              Revision Number OONJmt #
 Sheet Numb e r~~~--'-7~~~~~                  Effective for consumption on or
 Page~~~~~~~3~o~f~8~~~~                                  after July 1, 2010
                              EL PASO ELECTRIC COMPANY

                                   SCHEDULE NO. 08
                            GOVERNMENTAL STREET LIGHTING
                               AND SIGNAL SERVICE RATE



                OVERHEAD SYSTEM - HIGH PRESSURE SODIUM VAPOR
                           COMPANY OWNED - WOOD POLE
                   -
                                                            Total         Perla~
             '
                                                           Wattage          Charg_E?
1 OOW -   8,500 Lumen - 35 Foot Maximum Mounting Height      124            $15.20
150W -    14,400 Lumen - 35 Foot Maximum Mountinq Heiqht     i93            $16.49
250W -    23,200 Lumen - 35 Foot fV1axlmum Mounting Height  313             $19.18
400W -    50,000 Lumen - 50 Foot Maximum Mountinq Heiqht    485             $27.02


                ORNAMENTAL HIGH PRESSURE SODIUM VAPOR -
              NON-COMPANY OWNED, OPERATED AND MAINTAINED
-·                                                   Total                Per Lamp
                                                    Wattage                Charge
?OW - 5,300 Lumen                                      82                    $1.67
150W -1_4,400 Lumen                                   193                    $3.04
175W- 14,400 Lumen
250W - 16,000 Lumen
                                                      210
                                                      295
                                                                             $6.65
                                                                             $3.94     j
                      HIGH PRESSURE SODIUM VAPOR-
                 ROADWAY ILLUMINATION- NON COMPANY OWNED
                                                      Total               Per Lamp
                                                     Watta_qe              Cha roe
100W- HPS                                                        124        $2.04
 150W- HPS                                                       193        $5.02
 250W-HPS
>----·
                                                                  313       $5.08
400W- HPS                                                         485        $13.48
                                                          l"iJ!:>UG UTiUTY COMMi0,~1;;'

MONTHLY RA TE
                                                         JUL 3 0 ' 1'0   DOCKET        3 769 Q
Traffic Signal Lights
.----~~-~~~,~~~·
                        INCANDESCENT TRAFFIC SfGNALS
                                                           Wattage of        on y
                                   Type and Hours         Incandescent      Rate
                                    Of 0 eration              Lam          Per Unit
                        24 Hours                               61           $1.24
                        24 Hours                               61 - - ' - - '$1.24
                                                                             ----'




Section Number          1
                 ~--....._~~~~
                                              Revision Number_ ____,,2=0_ _ _ __
Sheet Number            7
               ~-~--'--~~~~
                                              Effective for consumption on or
Page~-~~-~~4~o~f8;..._~~~-                               after July 1. 2010
                               EL PASO ELECTRIC COMPANY

                                   SCHEDULE NO. 08
                            GOVERNMENTAL STREET LIGHTING
                               ANO SIGNAL SERVICE RATE

~Lame Head                 24 Hours                                               103            $2.09
 3 Lamp Head               18 Hours Normal, 6 Hours Flashing                      103            $2.09
 5 Lamp Head               24 Hours                                               133            $2.72
 4 Lamp    Head            18 Hours Normal, 6 Hours Flashing                      103            $2.09
 3 Lamp    Head            24 Hours                                               133            $2.72
 3 Lame    Head            18 Hours Normal, 6 Hours Flashinq                      133            $2.72
 4 Lamp    Head            24 Hours                                               133            $2.72
 ~J-ame Head               18 Hours Normal, 6 Hours Flashing                      133            $2.72
  2 Unit Walk Light        24 Hours                                               61             $1.24
  2 Unit Walk Lh::iht      24 Hours                                               103            $2.09
  2 Unit Walk Light        18 Hours Normal, 6 Hours Flashinq                      103            $2.09
                                                                              -         ~




  1 Unit Flashing          24 Hours                                               103            $2.09                '
  1 Unit Flashing          24 Hours                                               133            $2.72
  2 Unit Flashinq          24 Hours                                               103            $2.09
  2 Unit School Flashers   351 Annual Burning Hours                 ·>-~
                                                                                  103       -    $2.09
  2 Unit School Flashers   790 Annual Burninq Hours                               133            $2.72
  30 Watt Controller       24 Hours                                               30             $0.61 --
1 100 Watt Controller      24 Hours                            ··-~..I   ..
                                                                                  100            $2.60


                     LIGHT-EMITTING DIODE ("LED") TRAFFIC SIGNALS
~·                             -
                                                              Wattage of
                                                                High-                           Monthly
                                     Type and Hours           Efficiency                         Rate
         Type of Unit                  Of Operation           LED Lamp                          Per Unit
 3   Lamp Head              18 Hours Normal, 6 Hours Flashing     14                             $0.34
 5   Lamp Head              24 Hours                              14                             $0.6
4    Lamp Head              18 Hours Normal, 6 Hours Flashinq     14                             $0.~
3    Lamp Head              24 Hours                              14                             $0.3
3    Lamp Head              18 Hours Normal, 6 Hours Flashing     14                             $0.~
4    Lamp Head              24 Hours                              14                             $0.69;; --·
4    Lamp Head              18 Hours Normal, 6 Hours Flashing     14                             $0.6~) .~,·
2    Unit Walk Liqht        24 Hours                               9                             $0.2$b
2    Unit Walk Light        18 Hours Normal, 6 Hours Flashing      9                             $0 23'.5 ~::
                                                                                                    .........   1••



 i   Unit Flashing          24 Hours                              14                             $0.18>,:: 1 ;,
2    Unit Flashing          24 Hours                              14                             $0.352
2    Unit School Flashers   351 Annual Burning Hours              14                             $0.28::.:1
2    Unit School Flashers   790 Annual Burning Hours              14                             $0.28     :s
4    Unit School Flashers   351 Annual Burning Hours --           14                             $0.69 ';:'
4    Unit School Flashers   790 Annua! Burning Hours              14                             $0.69 -




Section Number       1                           Revision Number_ _~2_0_ _ _ _ __
              ~~--~-~--
Sheet Number_ _ ___.;.?_ _ _ __                  Effective for consumption on or
Page~~---~~5~o~f~8----~~-                                   after July 1, 2010
                                                                                PU8UC UTlUT'                 Q;:: TEXfJ

                                     EL PASO ELECTRIC COMPANY
                                                                                       1

                                          SCHEDULE NO. 08
                                                                                JUL 3 0 10       DOCl\\:T   3 7690
                                   GOVERNMENTAL STREET LIGHTING
                                      AND SIGNAL SERVICE RATE

    MONTHLY RATE PER UNIT

    Street lights and traffic signal lights that do not operate under any of the preceding
    conditions will be billed under the rate with the closest operating conditions.

    MERCURY VAPOR CLOSED TO NEW INSTALLATIONS AND
    CONVERSION/REPLACEMENT OF EXISTING INSTALLATIONS

    Mercury Vapor lamp categories are closed to new installations. The Company wit!
    continue to maintain existing Mercury Vapor installations and will, at the Company's
    option, install High Pressure Sodium Vapor ballasts in place of defective non-repairable
    Mercury Vapor ballasts. Customers with existing fixtures which are defective and must
    be replaced will have the option to convert its service to high pressure sodium vapor
    lamps or may cancel service at no cost.

    Mercury Vapor Fixture Replacement Schedule

    For Company owned lights, when existing mercury vapor fixtures require replacement,
    the Company will make such replacements with comparable high pressure sodrum vapor
    lighi1ng at no cost, as specified below:
                  Mercury Vapor - Overhead System - Company Owned,
                           35 Foot Mounting Height - Wood Pol~----~----~
r     Existing Mercury Vapor Lighting:     High Pressure Sodium Vapor Replacement:
      Wattaqe      Lu mens         kWh        Wattage        Lu mens       kWh
        195          7,000          70          124           8,500         44
       275          1 i ,000        98          193           14,400        69
         460           20,000          164             313             23,200              112
         920          20,0000          328             313*            23,200              112

                 Mercury Vapor - Overhead System - Company Owned,

      Existing Mercury Vapor Lighting:
                                                          -
                                              . ht Stee I Poe
                          30 F00t M oun fmg He1g            I
                                          High Pressure Sodium Vapor Replacement:
      Wattage      Lu mens       kWh         Wattage          Lu mens     kWh
        460         20,000        164           313            23,200     112
       920         20,0000        328          313*            23,200     112 ·--
    *O=Double - Mercury Vapor with double lamps on a single pole will be converted to two
                separate poles with a Single High Pressure Sodium Vapor lamp each.

    For Non-Company owned lights, upon the request of the Customer, the Company will
    convert or replace facilities with the high pressure sodium vapor lighting options listed
    below, at an amount equal to all applicable costs of such conversion or replacement.




    Section Number             1
                    ~~~----~~~~~
                                                        Revision Number_ _~2~0_ _ _ _ __
    SheetNumber~~~~~7~~~-~                              Effective for consumption on or
    Page_~~~~~-6""--"o~f=8~--~                                     after July 1, 2010
                                     EL PASO ELECTRIC COMPANY

                                         SCHEDULE NO. 08
                                  GOVERNMENTAL STREET LIGHTING
                                     AND SIGNAL SERVICE RATE


      Mercury vaeor - Non-Company 0 wned Systems -Interstate or Freewav L"lg ht mg
I
       Existing M~ury Vaeor Lighting:   High Pressure Sodium Vapor Replacement:
      Wattage      Lu mens      kWh        Wattage        Lu mens         kWh
         292         11,000      104         193           16,000          69           ~




        460          20,000      164         313           23,200          112
        1102         60,000      393         485           45,000          173



                                                                                            lacement:
                                                                                             kWh
                                                                                              44
    At the time of the replacement, the Customer wlll be billed at the applicable rate charge
    and associated kWh usage for the high pressure sodium vapor replacement lighting.

    Mercury Vapor Fixture Conversion Or Replacement Of Existing Facilities

    Upon the request of the Customer, the Company will convert or replace existing
    Company owned mercury vapor lighting to applicable Company offered street lighting
    options other than those indicated above.

    Upon the request of and payment by the Customer, the Company will convert existing
    Company owned facilities (size or type of luminaire) to a different applicable Company
    offered size or type of luminaire at an amount equal to ail applicable costs less the
    salvage value of the existing facilities.                                                      (./')
                                                                                                   -5           0
                                                                                                   GI
                                                                                                   !-
                                                                                                                0'
    Upon the request of and payment by the Customer, the Company will replace existing ~!...                    ....0
                                                                                              c:i               f'-..
    Company owned lighting facilities at an amount equal to all applicable costs less the     ;;;:;;;:          !'t'\
                                                                                              C)
    salvage value of the existing facilities. Installation of new facilities requested by the ('/iD
    Customer will be performed pursuant to the applicable Schedule and lamp category          f!'2 ~~           l-


                                                                                              ,,~~~
                                                                                                                u.1
    described above.                                                                                            ~---"'
                                                                                                ..... .,~   ~   0__,
                                                                                                   CS~~
                                                                                                     11·        Cl       ~
    FIXED FUEL FACTOR                                                                              r::<
                                                                                                   :::i
                                                                                                                         _!
                                                                                                                         0
                                                                                                                c:::>    tiC
    The above rates are subject to the provisions of the Company's Tariff Schedule No. 98          §            ;:---    I-
    entitled Fixed Fuel Factor.                                                                     S.1!        0        z.
                                                                                                   s            """'
                                                                                                                --'
                                                                                                                         0
                                                                                                                         0
    ENERGY EFFICIENCY COST RECOVERY FACTOR                                                          fr          ::::=>
                                                                                                                ~


    The above rates are subject to the provisions of the Company's Tariff Schedule No. 97,
    entitled Energy Efficiency Cost Recovery Factor.




    Section Number____1-'-------                          Revision Number~-~~~--~~    20
    Sheet Number~---"'--~-~--
                       7                                  Effective for consumption on or
    Pa ge_ _ _ _~--7~o_f_8_ _~~-                                     after July 1, 2010
                                EL PASO ELECTRIC COMPANY

                                    SCHEDULE NO. 08
                             GOVERNMENTAL STREET LIGHTING
                                AND SIGNAL SERVICE RATE

MILITARY BASE DISCOUNT RECOVERY FACTOR

The above rates are subject to the provisions of the Company's Tariff Schedule No. 96,
entitled Military Base Discount Recovery Factor.

TERMS OF PAYMENT

The due date of the bill for utility service shall not be less than sixteen (16) days after
issuance. A bill becomes delinquent if not received at the Company by the due date.

TERMS AND CONDITIONS

The Company's Rules and Regulations apply to service under this rate schedule.

Specific terms are as covered in various written agreements.




                                                                   JUL 3 0 '10    DOC!<ET
                                                                                              3 7690
                                                                     CONTFIOL#
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Section Number____1.,___ _ _ __                      Revision Number_ _---'2=0"-------
SheetNurnber_ _ _ _7 ' - - - - - - -                 Effective for consumption on or
Page~-------"-8~o~f~8---~                                       after July 1, 201 O
    APPENDIX




QUALIFICATIONS OF


DENNIS   W. GOINS
Blank Page
                                DENNIS W. GOINS



PRESENT POSITION
Economic Consultant, Potomac Management Group, Alexandria, VA

PREVIOUS POSITIONS
      11111   Vice President, Hagler, Bailly & Company, Washington, DC
      iii     Principal, Resource Consulting Group, Inc., Cambridge, MA
      111     Senior Associate, Resource Planning Associates, Inc., Cambridge, MA
      iii     Economist, North Carolina Utilities Commission, Raleigh, NC

EDUCATION
                    College                     Major           Degree
      Wake Forest University                  Economics           BA
      North Carolina State University         Economics          ME
      North Carolina State University         Economics          PhD


RELEVANT EXPERIENCE
Dr. Goins specializes in pricing, planning, and market structure issues affecting
firms that buy and sell products in electricity and natural gas markets. He has
extensive experience in evaluating competitive market conditions, analyzing
power and fuel requirements, prices, market operations, and transactions,
developing product pricing strategies, setting rates for energy-related products and
services, and negotiating power supply and natural gas contracts for private and
public entities. He has participated in more than 150 cases as an expert on
competitive market issues, utility restructuring, power market planning and
operations, utility mergers, rate design, cost of service, and management prudence
before the Federal Energy Regulatory Commission, the General Accounting
Office (now the Government Accountability Office), the First Judicial District
Court of Montana, the Circuit Court of Kanawha County, West Virginia, the Linn
County District Court of Iowa, and regulatory commissions in Alabama, Arizona,
Arkansas, Colorado, Florida, Georgia, Hawaii, Idaho, Illinois, Indiana, Kansas,
Kentucky, Louisiana, Maine, Maryland, Massachusetts, Minnesota, Mississippi,
Missouri, New Jersey, New York, North Carolina, Ohio, Oklahoma, South
Carolina, Texas, Utah, Vermont, Virginia, West Virginia, Wyoming, and the
District of Columbia. He has also prepared an expert report on behalf of the
                             Dennis W. Goins

United States regarding pricing and contract issues in a case before the United
States Court of Federal Claims.


PARTICIPATION IN REGULATORY, ADMINISTRATIVE, AND COURT
PROCEEDINGS
   1. Potomac Electric Power Company, before the Maryland Public Service
      Commission, Case No. 9286 (2012), on behalf of the General Services
      Administration, re retail cost recovery.
  2. Indiana Michigan Power Company, before the Indiana Utility Regulatory
     Commission, Cause No. 44075 (2012), on behalf of Steel Dynamics, Inc., re
     retail cost-of-service and fuel and purchased power cost recovery.
  3. Entergy Texas, Inc., before the Public Utilities Commission of Texas, PUC
     Docket No. 39896 (2012), on behalf of Texas Cities, re cost of service and
     retail rate design.
  4. Potomac Electric Power Company, before the District of Columbia Public
     Service Commission, Formal Case No. 1087 (2012), on behalf of the
     General Services Administration, re retail cost recovery.
  5. Dominion North Carolina Power, before the North Carolina Utilities
     Commission, Docket No. E-22, Sub 474 (2011), on behalf of Nucor Steel-
     Hertford, re fuel rate adjustments.
  6. Mid-Kansas Electric Company, before the Kansas Corporation
     Commission, Docket No. 1 l-GIME-597-GIE (2011),on behalf of Kansas
     Electric Power Cooperative, Inc., re local delivery service and operating
     agreements.
  7. Duke Energy Corporation et al., before the Federal Energy Regulatory
     Commission, Docket No. ECI 1-60-000 (2011), on behalf of the North
     Carolina Electric Membership Corporation, re merger-related market power
     issues.
  8. Resale Power Group of Iowa et al., before the Linn County District Court of
     Iowa, Case No. LACV 054271 (2011), on behalf of Central Iowa Power
     Cooperative, re compensation for unauthorized transmission access.
  9. Columbus Southern Power Company et al., before the Public Utilities
     Commission of Ohio, Case No. 11-346-EL-SSO et al., (2011), on behalf of
     the OMA Energy Group., re standard service offer electric security plan rate
     design issues.




                                          2
                             Dennis W. Goins

I 0. Appalachian Power Company and Wheeling Power Company, dba
     American Electric Power, before the Public Service Commission of West
     Virginia, Case No. 11-0274-E-GI (2011), on behalf of Steel of West
     Virginia, Inc., re expanded net energy cost rate issues.
11. Rocky Mountain Power Company, before the Wyoming Public Service
    Commission, Docket No. 20000-384-ER-10 (2011), on behalf of Cimarex
    Energy Company, QEP Field Services Company, and Kinder Morgan
    Interstate Gas Transmission, re utility rates, cost-of-service, and resource
    acquisition issues.
12. Duke Energy Indiana, Inc., before the Indiana Utility Regulatory
    Commission, Cause No. 43955 (2011 ), on behalf of Nucor Steel and Steel
    Dynamics, Inc., re utility-sponsored energy efficiency programs.
13. Kansas City Power & Light Company, before the Missouri Public Service
    Commission, Case No. ER-2010-0355 (2010), on behalf of the U.S.
    Department of Energy (Federal Executive Agencies), re cost-of-service and
    rate design issues.
14. Appalachian Power Company and Wheeling Power Company, dba
    American Electric Power, before the Public Service Commission of West
    Virginia, Case No. 10-0699-E-42T (2010), on behalf of Steel of West
    Virginia, Inc., re cost-of-service and rate design issues.
15. Entergy Arkansas, Inc., before the Arkansas Public Service Commission,
    Docket No. 10-010-U (2010), on behalf of Arkansas Electric Energy
    Consumers, Inc., re industrial opt out of utility-sponsored energy efficiency
    programs.
16. Indiana Michigan Power Company, before the Indiana Utility Regulatory
    Commission, Cause No. 38702 - FAC 62-Sl (2010), on behalf of Steel
    Dynamics, Inc., re fuel and purchased power cost recovery.
17. Dominion North Carolina Power, before the North Carolina Utilities
    Commission, Docket No. E-22, Sub 459 (2010), on behalf of Nucor Steel-
    Hertford, re cost of service and retail rate design.
18. Dominion North Carolina Power, before the North Carolina Utilities
    Commission, Docket No. E-22, Sub 461 (2010), on behalf of Nucor Stcel-
    Hertford, re fuel rate adjustments.
19. Entergy Texas, Inc., before the Public Utilities Commission of Texas, PUC
    Docket No. 37744 (2010), on behalf of Texas Cities, re cost of service and
    retail rate design.
20. Kentucky Utilities, Inc., before the Kentucky Public Service Commission,
    Case No. 2009-00548 (2010), on behalf of the Kentucky Industrial Utility
    Customers, re interruptible rates.


                                          3
                            Dennis W. Goins

21. Louisville Gas and Electric Company, Inc., before the Kentucky Public
    Service Commission, Case No. 2009-00549 (2010), on behalf of the
    Kentucky Industrial Utility Customers, re interruptible rates.
22. Ohio Edison et al., before the Public Utilities Commission of Ohio, Case
    No. 09-1948-EL-POR et al., (2010), on behalf of Nucor Steel Marion, Inc.,
    re energy efficiency and peak demand reduction portfolios.
23. Kauai Island Utility Cooperative, before the Hawaii Public Utilities
    Commission, Docket No. 2009-0050 (2010), on behalf of Kauai Marriott
    Resort & Beach Club, re retail cost allocation and rate design issues.
24. Entergy Arkansas, Inc., before the Arkansas Public Service Commission,
    Docket No. 09-024-U (2009), on behalf of Arkansas Electric Energy
    Consumers, Inc., re power plant environmental retrofit.
25. Appalachian Power Company, before the Virginia State Corporation
    Commission, Case No. PUE-2009-00030 (2009), on behalf of Steel
    Dynamics, Inc., re retail cost allocation and rate design issues.
26. Ohio Edison et al., before the Public Utilities Commission of Ohio, Case
    No. 09-906-EL-SSO (2009), on behalf of Nucor Steel Marion, Inc., re
    market rate offer.
27. Dominion North Carolina Power, before the North Carolina Utilities
    Commission, Docket No. E-22, Sub 456 (2009), on behalf of Nucor Steel-
    Hertford, re fuel cost adjustment.
28. Appalachian Power Company, before the Virginia State Corporation
    Commission, Case No. PUE-2009-00068 (2009), on behalf of Steel
    Dynamics, Inc., re demand response programs.
29. Indiana Michigan Power Company, before the Indiana Utility Regulatory
    Commission, Cause No. 43750 (2009), on behalf of Steel Dynamics, Inc., re
    wind power purchased power agreement.
30. Entergy Arkansas, Inc., before the Arkansas Public Service Commission,
    Docket No. 07-085-TF (2009), on behalf of Arkansas Electric Energy
    Consumers, Inc., re energy efficiency cost recovery.
31. CenterPoint Energy Arkansas Gas, before the Arkansas Public Service
    Commission, Docket No. 07-081-TF (2009), on behalf of Arkansas Gas
    Consumers, Inc., re energy efficiency cost recovery.
32. South Carolina Electric & Gas Company, before the South Carolina Public
    Service Commission, Docket No. 2009-261-E (2009), on behalf of CMC
    Steel-SC, re DSM cost recovery surcharge.




                                        4
                            Dennis W. Goins

33. Duke Energy Indiana, Inc., before the Indiana Utility Regulatory
    Commission, Cause No. 38707 FAC81 (2009), on behalf of Steel
    Dynamics, Inc., re fuel and purchased power cost recovery.
34. Potomac Electric Power Company, before the District of Columbia Public
    Service Commission, Formal Case No. 1076 (2009), on behalf of the
    General Services Administration, re retail cost allocation and standby rate
    design issues for distributed generation resources.
35. Appalachian Power Company, before the Virginia State Corporation
    Commission, Case No. PUE-2009-00039 (2009), on behalf of Steel
    Dynamics, Inc., re environmental and reliability cost recovery.
36. Indiana Michigan Power Company, before the Indiana Utility Regulatory
    Commission, Cause No. 38702 - FAC 63 (2009), on behalf of Steel
    Dynamics, Inc., re fuel and purchased power cost recovery.
37. Appalachian Power Company, before the Virginia State Corporation
    Commission, Case No. PUE-2009-302-00038 (2009), on behalf of Steel
    Dynamics, Inc., re fuel and purchased power cost recovery.
38. South Carolina Electric & Gas Company, before the South Carolina Public
    Service Commission, Docket No. 2008-302-E (2008), on behalf of CMC
    Steel-SC, re fuel and purchased power cost recovery.
39. South Carolina Electric & Gas Company, before the South Carolina Public
    Service Commission, Docket No. 2008-196-E (2008), on behalf of CMC
    Steel-SC, re base load review order for a nuclear facility.
40. Ohio Edison et al., before the Public Utilities Commission of Ohio, Case
    No. 08-935-EL-SSO et al. (2008), on behalf of Nucor Steel Marion, Inc., re
    standard service offer via an electric security plan.
41. Ohio Edison et al., before the Public Utilities Commission of Ohio, Case
    No. 08-936-EL-SSO (2008), on behalf of Nucor Steel Marion, Inc., re
    market rate offer via a competitive bidding process.
42. Alabama Power Company, before the Alabama Public Service Commission,
    Docket No. 18148 (2008), on behalf of CMC Steel Alabama, Nucor Steel
    Birmingham, Inc., and Nucor Steel Tuscaloosa, Inc, re energy cost recovery.
43. Entergy Texas, Inc., before the Public Utilities Commission of Texas, PUC
    Docket No. 35269 (2008), on behalf of Texas Cities, re jurisdictional
    allocation of system agreement payments.
44. Duke Energy Indiana, Inc., before the Indiana Utility Regulatory
    Commission, Cause No. 43374 (2008), on behalf of Nucor Steel and Steel
    Dynamics, Inc., re alternative regulatory plan.




                                         5
                             Dennis W. Goins

45. Entergy Gulf States Inc., before the Public Utilities Commission of Texas,
    PUC Docket No. 34800 (2008), on behalf of Texas Cities, re affiliate
    transactions.
46. Commonwealth Edison Company, before the Illinois Commerce
    Commission, Docket No. 07-0566 (2008), on behalf of Nucor Steel
    Kankakee, Inc., re cost-of-service and rate design issues.
47. Ohio Edison et al., before the Public Utilities Commission of Ohio, Case
    No. 07-0551-EL-AIR et al. (2008), on behalf of Nucor Steel Marion, Inc., re
    cost-of-service and rate design issues.
48. Appalachian Power Company dba American Electric Power, before the
    Public Service Commission of West Virginia, Case No. 06-0033-E-CN
    (2007), on behalf of Steel of West Virginia, Inc., re power plant cost
    recovery mechanism.
49. Oncor Electric Delivery Company and Texas Energy Future Holdings
    Limited Partnership, before the Public Utilities Commission of Texas, PUC
    Docket No. 34077 (2007), on behalf of Nucor Steel - Texas, re acquisition
    of TXU Corp. by Texas Energy Future Holdings Limited Partnership.
50. Arkansas Oklahoma Gas Company, before the Arkansas Public Service
    Commission, Docket No. 07-026-U (2007), on behalf of West Central
    Arkansas Gas Consumers, re gas cost-of-service and rate design issues.
51. Idaho Power Company, before the Idaho Public Utilities Commission, Case
    No. IPC-E-07-08 (2007), on behalf of the U.S. Department of Energy
    (Federal Executive Agencies), re cost-of-service and rate design issues.
52. Potomac Electric Power Company, before the District of Columbia Public
    Service Commission, Formal Case No. 1056 (2007), on behalf of the
    General Services Administration, re demand-side management and
    advanced metering programs.
53. South Carolina Electric & Gas Company, before the South Carolina Public
    Service Commission, Docket No. 2007-229-E (2007), on behalf of CMC
    Steel-SC, re cost-of-service and rate design issues.
54. Potomac Electric Power Company, before the Maryland Public Service
    Commission, Case No. 9092 (2007), on behalf of the General Services
    Administration, re retail cost allocation and standby rate design issues for
    distributed generation resources.
55. Potomac Electric Power Company, before the District of Columbia Public
    Service Commission, Formal Case No. 1053 (2007), on behalf of the
    General Services Administration, re retail cost allocation and standby rate
    design issues for distributed generation resources.



                                          6
                            Dennis W. Goins

56. Entergy Gulf States Inc., before the Public Utilities Commission of Texas,
    PUC Docket No. 32907 (2006), on behalf of Texas Cities, re hurricane cost
    recovery.
57. Entergy Gulf States Inc., before the Public Utilities Commission of Texas,
    PUC Docket No. 32710/ SOAR Docket No. XXX-XX-XXXX (2006), on behalf
    of Texas Cities, re reconciliation of fuel and purchased power costs.
58. Florida Power & Light Company, before the Florida Public Service
    Commission, Docket No. 060001-EI (2006), on behalf of the U.S. Air Force
    (Federal Executive Agencies), re fuel and purchased power cost recovery.
59. Arizona Public Service Company, before the Arizona Corporation
    Commission, Docket No. E-01345A-05-0816 (2006), on behalf of the U.S.
    Air Force (Federal Executive Agencies), re retail cost allocation and rate
    design issues.
60. PacifiCorp (dba Rocky Mountain Power), before the Utah Public Service
    Commission, Docket No. 06-035-21 (2006), on behalf of the U.S. Air Force
    (Federal Executive Agencies), re rate design issues.
61. South Carolina Electric & Gas Company, before the South Carolina Public
    Service Commission, Docket No. 2006-2-E (2006), on behalf of CMC
    Steel-SC, re fuel and purchased power cost recovery.
62. Entergy Gulf States Inc., before the Public Utilities Commission of Texas,
    PUC Docket No. 31544/ SOAR Docket No. XXX-XX-XXXX (2006), on behalf
    of Texas Cities, re transition to competition rider.
63. Idaho Power Company, before the Idaho Public Utilities Commission, Case
    No. IPC-E-05-28 (2006), on behalf of the U.S. Department of Energy
    (Federal Executive Agencies), re cost-of-service and rate design issues.
64. Alabama Power Company, before the Alabama Public Service Commission,
    Docket No. 18148 (2005), on behalf of SMI Steel-Alabama, re energy cost
    recovery.
65. Florida Power & Light Company, before the Florida Public Service
    Commission, Docket No. 050001-EI (2005), on behalf of the U.S. Air Force
    (Federal Executive Agencies), re fuel and capacity cost recovery.
66. Entergy Gulf States Inc., before the Public Utilities Commission of Texas,
    PUC Docket No. 31315/ SOAR Docket No. XXX-XX-XXXX (2005), on behalf
    of Texas Cities, re incremental purchased capacity cost rider.
67. Florida Power & Light Company, before the Florida Public Service
    Commission, Docket No. 050045-EI (2005), on behalf of the U.S. Air Force
    (Federal Executive Agencies), re cost-of-service and interruptible rate
    issues.



                                         7
                            Dennis W. Goins

68. Arkansas Electric Cooperative Corporation, before the Arkansas Public
    Service Commission, Docket No. 05-042-U (2005), on behalf of Nucor
    Steel and Nucor-Yamato Steel, re power plant purchase.
69. Arkansas Electric Cooperative Corporation, before the "Arkansas Public
    Service Commission, Docket No. 04-141-U (2005), on behalf of Nucor
    Steel and Nucor-Yamato Steel, re cost-of-service and rate design issues.
70. Dominion North Carolina Power, before the North Carolina Utilities
    Commission, Docket No. E-22, Sub 412 (2005), on behalf of Nucor Steel-
    Hertford, re cost-of-service and interruptible rate issues.
71. Public Service Company of Colorado, before the Colorado Public Utilities
    Commission, Docket No. 04S-164E (2004), on behalf of the U.S. Air Force
    (Federal Executive Agencies), re cost-of-service and interruptible rate
    issues.
72. CenterPoint Energy Houston Electric, LLC, et al., before the Public Utility
    Commission of Texas, PUC Docket No. 29526 (2004), on behalf of the
    Coalition of Commercial Ratepayers, re stranded cost true-up balances.
73. PacifiCorp, before the Utah Public Service Commission, Docket No. 04-
    035-11 (2004), on behalf of the U.S. Air Force (United States Executive
    Agencies), re time-of-day rate design issues.
74. Arizona Public Service Company, before the Arizona Corporation
    Commission, Docket No. E-01345A-03-0347 (2004), on behalf of the U.S.
    Air Force (Federal Executive Agencies), re retail cost allocation and rate
    design issues.
75. Idaho Power Company, before the Idaho Public Utilities Commission, Case
    No. IPC-E-03-13 (2004), on behalf of the U.S. Department of Energy
    (Federal Executive Agencies), re retail cost allocation and rate design
    issues.
76. PacifiCorp, before the Utah Public Service Commission, Docket No. 03-
    2035-02 (2004), on behalf of the U.S. Air Force (United States Executive
    Agencies), re retail cost allocation and rate design issues.
77. Dominion Virginia Power, before the Virginia State Corporation
    Commission, Case No. PUE-2000-00285 (2003), on behalf of Chaparral
    (Virginia) Inc., re recovery of fuel costs.
78. Jersey Central Power & Light Company, before the New Jersey Board of
    Public Utilities, BPU Docket No. ER02080506, OAL Docket No. PUC-
    7894-02 (2002-2003), on behalf of New Jersey Commercial Users, re retail
    cost allocation and rate design issues.




                                         8
                             Dennis W. Goins

79. Public Service Electric and Gas Company, before the New Jersey Board of
    Public Utilities, BPU Docket No. ER02050303, OAL Docket No. PUC-
    5744-02 (2002-2003), on behalf of New Jersey Commercial Users, re retail
    cost allocation and rate design issues.
80. South Carolina Electric & Gas Company, before the South Carolina Public
    Service Commission, Docket No. 2002-223-E (2002), on behalf of SMI
    Steel-SC, re retail cost allocation and rate design issues.
81. Montana Power Company, before the First Judicial District Court of
    Montana, Great Falls Tribune et al. v. the Montana Public Service
    Commission, Cause No. CDV2001-208 (2002), on behalf of a media
    consortium (Great Falls Tribune, Billings Gazette, Montana Standard,
    Helena Independent Record, Missoulian, Big Sky Publishing, Inc. dba
    Bozeman Daily Chronicle, the Montana Newspaper Association, Miles City
    Star, Livingston Enterprise, Yellowstone Public Radio, the Associated
    Press, Inc., and the Montana Broadcasters Association), re public disclosure
    of allegedly proprietary contract information.
82. Louisville Gas & Electric et al., before the Kentucky Public Service
    Commission, Administrative Case No. 387 (2001), on behalf of Gallatin
    Steel Company, re adequacy of generation and transmission capacity in
    Kentucky.
83. PacifiCorp, before the Utah Public Service Commission, Docket No. 01-
    035-01 (2001), on behalf of Nucor Steel, re retail cost allocation and rate
    design issues.
84. TXU Electric Company, before the Public Utilities Commission of Texas,
    PUC Docket No. 23640/ SOAH Docket No. XXX-XX-XXXX (2001), on behalf
    of Nucor Steel, re fuel eost recovery.
85. FPL Group et al., before the Federal Energy Regulatory Commission,
    Docket No. ECOl-33-000 (2001), on behalf of Arkansas Electric
    Cooperative Corporation, Inc., re merger-related market power issues.
86. Entergy Mississippi, Inc., et al., before the Mississippi Public Service
    Commission, Docket No. 2000-UA-925 (2001), on behalf of Birmingham
    Steel-Mississippi, re appropriate regulatory conditions for merger approval.
87. TXU Electric Company, before the Public Utilities Commission of Texas,
    PUC Docket No. 22350/ SOAH Docket No. XXX-XX-XXXX (2000), on behalf
    of Nucor Steel, re unbundled cost of service and rates.
88. PacifiCorp, before the Utah Public Service Commission, Docket No. 99-
    035-10 (2000), on behalf of Nucor Steel, re using system benefit charges to
    fund demand-side resource investments.




                                          9
                            Dennis W. Goins

89. Entergy Arkansas, Inc. et al., before the Arkansas Public Service
    Commission, Docket No. 00-190-U (2000), on behalf of Nucor-Yamato
    Steel and Nucor Steel-Arkansas, re the development of competitive electric
    power markets in Arkansas.
90. Entergy Arkansas, Inc. et al., before the Arkansas Public Service
    Commission, Docket No. 00-048-R (2000), on behalf of Nucor-Yamato
    Steel and Nucor Steel-Arkansas, re generic filing requirements and
    guidelines for market power analyses.
91. ScottishPower and PacifiCorp, before the Utah Public Service Commission,
    Docket No. 98-2035-04 (1999), on behalf of Nucor Steel, re merger
    conditions to protect the public interest.
92. Dominion Resources, Inc. and Consolidated Natural Gas Company, before
    the Virginia State Corporation Commission, Case No. PUA990020 (1999),
    on behalf of the City of Richmond, re market power and merger conditions
    to protect the public interest.
93. Houston Lighting & Power Company, before the Public Utility Commission
    of Texas, Docket No. 18465 (1998) on behalf of the Texas Commercial
    Customers, re excess earnings and stranded-cost recovery and mitigation.
94. PIM Interconnection, LLC, before the Federal Energy Regulatory
    Commission, Docket No. ER98-1384 (1998) on behalf of Wellsboro
    Electric Company, re pricing low-voltage distribution services.
95. DQE, Inc. and Allegheny Power System, Inc., before the Federal Energy
    Regulatory Commission, Docket Nos. ER97-4050-000, ER97-4051-000,
    and EC97-46-000 (1997) on behalf of the Borough of Chambersburg, re
    market power in relevant markets.
96. GPU Energy, before the New Jersey Board of Public Utilities, Docket No.
    E097070458 (1997) on behalf of the New Jersey Commercial Users Group,
    re unbundled retail rates.
97. GPU Energy, before the New Jersey Board of Public Utilities, Docket No.
    E097070459 (1997) on behalf of the New Jersey Commercial Users Group,
    re stranded costs.
98. Public Service Electric and Gas Company, before the New Jersey Board of
    Public Utilities, Docket No. E097070461 (1997) on behalf of the New
    Jersey Commercial Users Group, re unbundled retail rates.
99. Public Service Electric and Gas Company, before the New Jersey Board of
    Public Utilities, Docket No. E097070462 (1997) on behalf of the New
    Jersey Commercial Users Group, re stranded costs.




                                        10
                              Dennis W. Goins

100. DQE, Inc. and Allegheny Power System, Inc., before the Federal Energy
     Regulatory Commission, Docket Nos. ER97-4050-000, ER97-4051-000,
     and EC97-46-000 (1997) on behalf of the Borough of Chambersburg,
     Allegheny Electric Cooperative, Inc., and Selected Municipalities, re market
     power in relevant markets.
101. CSW Power Marketing, Inc., before the Federal Energy Regulatory
     Commission, Docket No.ER97-1238-000 (1997) on behalf of the
     Transmission Dependent Utility Systems, re market power in relevant
     markets.
102. Central Hudson Gas & Electric Corporation et al., before the New York
     Public Service Commission, Case Nos. 96-E-0891, 96-E-0897, 96-E-0898,
     96-E-0900, 96-E-0909 (1997), on behalf of the Retail Council of New York,
     re st~anded-cost recovery.
103. Central Hudson Gas & Electric Corporation, supplemental testimony, before
     the New York Public Service Commission, Case No. 96-E-0909 (1997) on
     behalf of the Retail Council of New York, re stranded-cost recovery.
104. Consolidated Edison Company of New York, Inc., supplemental testimony,
     before the New York Public Service Commission, Case No. 96-E-0897
     (1997) on behalf of the Retail Council of New York, re stranded-cost
     recovery.
105. New York State Electric & Gas Corporation, supplemental testimony,
     before the New York Public Service Commission, Case No. 96-E-0891
     (1997) on behalf of the Retail Council of New York, re stranded-cost
     recovery.
106. Rochester Gas and Electric Corporation, supplemental testimony, before the
     New York Public Service Commission, Case No. 96-E-0898 (1997) on
     behalf of the Retail Council of New York, re stranded-cost recovery.
107. Texas Utilities Electric Company, before the Public Utility Commission of
     Texas, Docket No. 15015 (1996), on behalf of Nucor Steel-Texas, re real-
     time electricity pricing.
108. Central Power and Light Company, before the Public Utility Commission of
     Texas, Docket No. 14965 (1996), on behalf of the Texas Retailers
     Association, re cost of service and rate design.
109. Carolina Power & Light Company, before the South Carolina Public Service
     Commission, Docket No. 95-1076-E (1996), on behalf of Nucor Steel-
     Darlington, re integrated resource planning.
110. Texas Utilities Electric Company, before the Public Utility Commission of
     Texas, Docket No. 13575 (1995), on behalf of Nucor Steel-Texas, re
     integrated resource planning, DSM options, and real-time pricing.


                                          11
                               Dennis W. Goins

111. Arkansas Power & Light Company, et al., Notice of Inquiry to Consider
     Section 111 of the Energy Policy Act of 1992, before the Arkansas Public
     Service Commission, Docket No. 94-342-U (1995), Initial Comments on
     behalf of Nucor-Yamato Steel Company, re integrated resource planning
     standards.
112. Arkansas Power & Light Company, et al., Notice of Inquiry to Consider
     Section 111 of the Energy Policy Act of 1992, before the Arkansas Public
     Service Commission, Docket No. 94-342-U (1995), Reply Comments on
     behalf of Nucor-Yamato Steel Company, re integrated resource planning
     standards.
113. Arkansas Power & Light Company, et al., Notice of Inquiry to Consider
     Section 111 of the Energy Policy Act of 1992, before the Arkansas Public
     Service Commission, Docket No. 94-342-U (1995), Final Comments on
     behalf of Nucor-Yamato Steel Company, re integrated resource planning
     standards.
114. South Carolina Pipeline Corporation, before the South Carolina Public
     Service Commission, Docket No. 94-202-G (1995), on behalf of Nucor
     Steel, re integrated resource planning and rate caps.
115. Gulf States Utilities Company, before the United States Court of Federal
     Claims, Gulf States Utilities Company v. the United States, Docket No. 91-
     l 118C (1994, 1995), on behalf of the United States, re electricity rate and
     contract dispute litigation.
116. American Electric Power Corporation, before the Federal Energy
     Regulatory Commission, Docket No. ER93-540-000 (1994), on behalf of
     DC Tie, Inc., re costing and pricing electricity transmission services.
117. Texas Utilities Electric Company, before the Public Utility Commission of
     Texas, Docket No. 13100 (1994), on behalf of Nucor Steel-Texas, re real-
     time electricity pricing.
118. Carolina Power & Light Company, et al., Proposed Regulation Governing
     the Recovery of Fuel Costs by Electric Utilities, before the South Carolina
     Public Service Commission, Docket No. 93-238-E (1994), on behalf of
     Nucor Steel-Darlington, re fuel-cost recovery.
119. Southern Natural Gas Company, before the Federal Energy Regulatory
     Commission, Docket No. RP93- l 5-000 (1993-1995), on behalf of Nucor
     Steel-Darlington, re costing and pricing natural gas transportation services.
120. West Penn Power Company, et al., v. State Tax Department of West
     Virginia, et al., Civil Action No. 89-C-3056 (1993), before the Circuit Court
     of Kanawha County, West Virginia, on behalf of the West Virginia
     Department of Tax and Revenue, re electricity generation tax.


                                           12
                              Dennis W. Goins

121. Carolina Power & Light Company, et al., Proceeding Regarding
     Consideration of Certain Standards Pertaining to Wholesale Power
     Purchases Pursuant to Section 712 of the 1992 Energy Policy Act, before
     the South Carolina Public Service Commission, Docket No. 92-231-E
     (1993), on behalf of Nucor Steel-Darlington, re Section 712 regulations.
122. Mountain Fuel Supply Company, before the Public Service Commission of
     Utah, Docket No. 93-057-01 (1993), on behalf of Nucor Steel-Utah, re
     costing and pricing retail natural gas firm, interruptible, and transportation
     services.
123. Texas Utilities Electric Company, before the Public Utility Commission of
     Texas, Docket No. 11735 (1993), on behalf of the Texas Retailers
     Association, re retail cost-of-service and rate design.
124. Virginia Electric and Power Company, before the Virginia State
     Corporation Commission, Case No. PUE92004 l (1993), on behalf of Philip
     Morris USA, re cost of service and retail rate design.
125. Carolina Power & Light Company, before the South Carolina Public Service
     Commission, Docket No. 92-209-E (1992), on behalf of Nucor Steel-
     Dariington.
126. Gulf States Utilities Company, before the Louisiana Public Service
     Commission, Docket No. U-17282, Rate Design (1992), on behalf of the
     Department of Energy, Strategic Petroleum Reserve.
127. Georgia Power Company, before the Georgia Public Service Commission,
     Docket Nos. 4091-U and 4146-U (1992), on behalf of Amicalola Electric
     Membership Corporation.
128. PacifiCorp, Inc., before the Federal Energy Regulatory Commission, Docket
     No. EC88-2-007 (1992), on behalf of Nucor Steel-Utah.
129. South Carolina Pipeline Corporation, before the South Carolina Public
     Service Commission, Docket No. 90-452-G (1991), on behalf of Nucor
     Steel-Darlington.
130. Carolina Power & Light Company, before the South Carolina Public Service
     Commission, Docket No. 91-4-E, 1991 Fall Hearing, on behalf of Nucor
     Steel-Darlington.
131. Sonat, Inc., and North Carolina Natural Gas Corporation, before the North
     Carolina Utilities Commission, Docket No. G-21, Sub 291 (1991), on behalf
     of Nucor Corporation, Inc.
132. Northern States Power Company, before the Minnesota Public Utilities
     Commission, Docket No. E002/GR-91-001 (1991), on behalf of North Star
     Steel-Minnesota.



                                           13
                              Dennis W. Goins

133. Gulf States Utilities Company, before the Louisiana Public Service
     Commission, Docket No. U-17282, Phase IV-Rate Design (1991), on behalf
     of the Department of Energy, Strategic Petroleum Reserve.
134. Houston Lighting & Power Company, before the Public Utility Commission
     of Texas, Docket No. 9850 (1990), on behalf of the Department of Energy,
     Strategic Petroleum Reserve.
135. General Services Administration, before the United States General
     Accounting Office, Contract Award Protest (1990), Solicitation No. GS-
     OOP-AC87-91, Contract No. GS-OOD-89-B5D-0032, on behalf of Satilla
     Rural Electric Membership Corporation, re cost of service and rate design.
136. Carolina Power & Light Company, before the South Carolina Public Service
     Commission, Docket No. 90-4-E (1990 Fall Hearing), on behalf of Nucor
     Steel-Darlington, re fuel-cost recovery.
137. Gulf States Utilities Company, before the Louisiana Public Service
     Commission, Docket No. U-17282, Phase III-Rate Design (1990), on behalf
     of the Department of Energy, Strategic Petroleum Reserve, re cost of service
     and rate design.
138. Atlanta Gas Light Company, before the Georgia Public Service
     Commission, Docket No. 3923-U (1990), on behalf of Herbert G. Burris
     and Oglethorpe Power Corporation, re anticompetitive pricing schemes.
139. Ohio Edison Company, before the Ohio Public Utilities Commission, Case
     No. 89-1001-EL-AIR (1990), on behalf of North Star Steel-Ohio, re cost of
     service and rate design.
140. Gulf States Utilities Company, before the Louisiana Public Service
     Commission, Docket No. U-17282, Phase III-Cost of Service/Revenue
     Spread (1989), on behalf of the Department of Energy, Strategic Petroleum
     Reserve.
141. Northern States Power Company, before the Minnesota Public Utilities
     Commission, Docket No. E002/GR-89-865 (1989), on behalf of North Star
     Steel-Minnesota.
142. Gulf States Utilities Company, before the Louisiana Public Service
     Commission, Docket No. U-17282, Phase III-Rate Design (1989), on behalf
     of the Department of Energy, Strategic Petroleum Reserve.
143. Utah Power & Light Company, before the Utah Public Service Commission,
     Case No. 89-039-10 (1989), on behalf of Nucor Steel-Utah and Vulcraft, a
     division of Nucor Steel.




                                          14
                            Dennis W. Goins

144. Soyland Power Cooperative, Inc. v. Central Illinois Public Service
     Company, Docket No. EL89-30-000 (1989), before the Federal Energy
     Regulatory Commission, on behalf of Soyland Power Cooperative, Inc., re
     wholesale contract pricing provisions
145. Gulf States Utilities Company, before the Public Utility Commission of
     Texas, Docket No. 8702 (1989), on behalf of the Department of Energy,
     Strategic Petroleum Reserve.
146. Houston Lighting and Power Company, before the Public Utility
     Commission of Texas, Docket No. 8425 (1989), on behalf of the
     Department of Energy, Strategic Petroleum Reserve.
147. Northern Illinois Gas Company, before the Illinois Commerce Commission,
     Docket No. 88-0277 (1989), on behalf of the Coalition for Fair and
     Equitable Transportation, re retail gas transportation rates.
148. Carolina Power & Light Company, before the South Carolina Public Service
     Commission, Docket No. 79-7-E, 1988 Fall Hearing, on behalf of Nucor
     Steel-Darlington, re fuel-cost recovery.
149. Potomac Electric Power Company, before the District of Columbia Public
     Service Commission, Formal Case No. 869 (1988), on behalf of Peoples
     Drug Stores, Inc., re cost of service and rate design.
150. Carolina Power & Light Company, before the South Carolina Public Service
     Commission, Docket No. 88-11-E (1988), on behalf of Nucor Steel-
     Darlington.
151. Northern States Power Company, before the Minnesota Public Utilities
     Commission, Docket No. E-002/GR-87-670 (1988), on behalf of the
     Metalcasters of Minnesota.
152. Ohio Edison Company, before the Ohio Public Utilities Commission, Case
     No. 87-689-EL-AIR (1987), on behalf of North Star Steel-Ohio.
153. Carolina Power & Light Company, before the South Carolina Public Service
     Commission, Docket No. 87-7-E (1987), on behalf of Nucor Steel-
     Darlington.
154. Gulf States Utilities Company, before the Louisiana Public Service
     Commission, Docket No. U-17282, Phase I (1987), on behalf of the
     Strategic Petroleum Reserve.
155. Gulf States Utilities Company, before the Public Utility Commission of
     Texas, Docket No. 7195 (1987), on behalf of the Strategic Petroleum
     Reserve.




                                        15
                                   Dennis W. Goins

156. Gulf States Utilities Company, before the Federal Energy Regulatory
     Commission, Docket No. ER86-558-006 (1987), on behalf of Sam Rayburn
     G&T Cooperative.
11 -t::.'7
      JI.    Utah Power & Light Company, before the Utah Public Service Commission,
             Case No. 85-035-06 (1986), on behalf of the U.S. Air Force.
158. Houston Lighting & Power Company, before the Public Utility Commission
     of Texas, Docket No. 6765 (1986), on behalf of the Strategic Petroleum
     Reserve.
159. Central Maine Power Company, before the Maine Public Utilities
     Commission, Docket No. 85-212 (1986), on behalf of the U.S. Air Force.
160. Gulf States Utilities Company, before the Public Utility Commission of
     Texas, Docket Nos. 6477 and 6525 (1985), on behalf of North Star Steel-
     Tcxas.
161. Ohio Edison Company, before the Ohio Public Utilities Commission,
     Docket No. 84-1359-EL-AIR (1985), on behalf of North Star Steel-Ohio.
162. Utah Power & Light Company, before the Utah Public Service Commission,
     Case No. 84-035-01 (1985), on behalf of the U.S. Air Force.
163. Central Vermont Public Service Corporation, before the Vermont Public
     Service Board, Docket No. 4782 (1984), on behalf of Central Vermont
     Public Service Corporation.
164. Gulf States Utilities Company, before the Louisiana Public Service
     Commission, Docket No. U-15641 (1983), on behalf of the Strategic
     Petroleum Reserve.
165. Southwestern Power Administration, before the Federal Energy Regulatory
     Commission, Rate Order SWPA-9 (1982), on behalf of the Department of
     Defense.
166. Public Service Company of Oklahoma, before the Federal Energy
     Regulatory Commission, Docket Nos. ER82-80-000 and ER82-389-000
     (1982), on behalf of the Department of Defense.
167. Central Maine Power Company, before the Maine Public Utilities
     Commission, Docket No. 80-66 (1981), on behalf of the Commission Staff.
168. Bangor Hydro-Electric Company, before the Maine Public Utilities
     Commission, Docket No. 80-108 (1981), on behalf of the Commission
     Staff.
169. Oklahoma Gas & Electric, before the Oklahoma Corporation Commission,
     Docket No. 27275 (1981), on behalf of the Commission Staff.




                                               16
                             Dennis W. Goins

170. Green Mountain Power, before the Vermont Public Service Board, Docket
     No. 4418 (1980), on behalf of the PSB Staff.
171. Williams Pipe Line, before the Federal Energy Regulatory Commission,
     Docket No. OR79-1 (1979), on behalf of Mapco, fac.
172. Boston Edison Company, before the Massachusetts Department of Public
     Utilities, Docket No. 19494 (1978), on behalf of Boston Edison Company.
173. Duke Power Company, before the North Carolina Utilities Commission,
     Docket No. E-7, Sub 173, on behalf of the Commission Staff.
174. Duke Power Company, before the North Carolina Utilities Commission,
     Docket No. E-100, Sub 32, on behalf of the Commission Staff.
175. Virginia Electric & Power Company, before the North Carolina Utilities
     Commission, Docket No. E-22, Sub 203, on behalf of the Commission
     Staff.
176. Virginia Electric & Power Company, before the North Carolina Utilities
     Commission, Docket No. E-22, Sub 170, on behalf of the Commission
     Staff.
177. Southern Bell Telephone Company, before the North Carolina Utilities
     Commission, Docket No. P-5, Sub 48, on behalf of the Commission Staff.
178. Western Carolina Telephone Company, before the North Carolina Utilities
     Commission, Docket No. P-58, Sub 93, on behalf of the Commission Staff.
179. Natural Gas Ratemaking, before the North Carolina Utilities Commission,
     Docket No. G-100, Sub 29, on behalf of the Commission Staff.
180. General Telephone Company of the Southeast, before the North Carolina
     Utilities Commission, Docket No. P-19, Sub 163, on behalf of the
     Commission Staff.
181. Carolina Power and Light Company, before the North Carolina Utilities
     Commission, Docket No. E-2, Sub 264, on behalf of the Commission Staff.
182. Carolina Power and Light Company, before the North Carolina Utilities
     Commission, Docket No. E-2, Sub 297, on behalf of the Commission Staff.
183. Duke Power Company, et al., Investigation of Peak-Load Pricing, before the
     North Carolina Utilities Commission, Docket No. E-100, Sub 21, on behalf
     of the Commission Staff.
184. Investigation of Intrastate Long Distance Rates, before the North Carolina
     Utilities Commission, Docket No. P-100, Sub 45, on behalf of the
     Commission Staff.




                                         17
                                                        Revised- Cities' Errata No. 3


          effect, ETI' s rate-year estimate assumes that the divestiture/merger
2         will have no effect on either the level of or method of recovering
 3        (via Schedule MSS-2 of the ESA) such costs. In addition, ETI
4         again ignored the effects of load growth when it set rate-year MSS-
 5        2 costs as adjusted test-year MSS-2 costs recovered in base rates.
 6        That is, by ignoring load growth in setting both PPCC and MSS-2
 7        costs that will be recovered in base rates, ETI almost certainly
 8        ensured that it will overrecover both types of costs going forward.
 9   7.   ETI' s principal rate schedules for street lighting and traffic signal
10        customers are Schedules SHL and TSS, respectively.           Schedule
11        SHL applies to lighting for public streets, roads, and thoroughfares
12        in cities and in subdivisions with an incorporated homeowners
13        association. Schedule SHL sets fixed monthly charges for standard
14        and nonstandard fixture and lamps that ETI installs and maintains
15        (Rate Groups A and C). ETI also offers a fixed kWh rate for
16        lighting facilities that the customer owns and maintains (Rate
17        Groups D and E).       Schedule TSS is a fixed kWh rate with a
18        monthly @ttst@m@r   tiMfffium charge per delivery point applicable to
19        customer-owned and -maintained traffic signals. Both proposed
20        rates do not reflect the lower cost of operating and maintaining
21        lighting facilities using energy-efficient light-emitting diode (LED)
22        bulbs.    Moreover, Schedule SHL includes a provision that
23        penalizes a customer that replaces a high-wattage bulb with a more
24        energy-efficient LED bulb.




                                                        Docket No. 39896
                                                        Dennis W. Goins - Direct
                                                        Page7
                                                        Revised- Cities' Errata No. 3


          effect, ETI' s rate-year estimate assumes that the divestiture/merger
 2        will have no effect on either the level of or method of recovering
 3        (via Schedule MSS-2 of the ESA) such costs. In addition, ETI
4         again ignored the effects of load growth when it set rate-year MSS-
 5        2 costs as adjusted test-year MSS-2 costs recovered in base rates.
 6        That is, by ignoring load growth in setting both PPCC and MSS-2
 7        costs that will be recovered in base rates, ETI almost certainly
 8        ensured that it will overrecover both types of costs going forward.
 9   7.   ETI's principal rate schedules f'or street lighting and traffic signal
10        customers are Schedules SHL and TSS, respectively.          Schedule
11        SHL applies to lighting for public streets, roads, and thoroughfares
12        in cities and in subdivisions with an incorporated homeowners
13        association. Schedule SHL sets fixed monthly charges for standard
14        and nonstandard fixture and lamps that ETI installs and maintains
15        (Rate Groups A and C). ETI also offers a fixed kWh rate for
16        lighting facilities that the customer owns and maintains (Rate
17        Groups D and E).       Schedule TSS is a fixed kWh rate with a
18        monthly minimum charge per delivery point applicable to
19        customer-owned and -maintained traffic signals. Both proposed
20        rates do not reflect the lower cost of operating and maintaining
21        lighting facilities using energy-efficient light-emitting diode (LED)
22        bulbs.    Moreover, Schedule SHL includes a provision that
23        penalizes a customer that replaces a high-wattage bulb with a more
24        energy-efficient LED bulb.




                                                       Docket No. 39896
                                                       Dennis W. Goins - Direct
                                                       Page7



                                                                                        {   ']
                                                                Revised - Cities' Errata No. 3


 1                             RECOMMENDATIONS

2    Q.   WHAT DO YOU RECOMMEND ON THE BASIS OF THESE
 3        CONCLUSIONS?

4    A.   I recommend that the Commission take the following actions regarding the
 5        major issues discussed in my testimony:
6            1.   Reject the AED4CP method used in ETI's jurisdictional separation
 7                study to assign demand-related production costs to its Texas retail
 8                and wholesale jurisdictions.      Instead, the Commission should
 9                require ETI to assign these costs to the wholesale jurisdiction using
10                the 12 coincident peak (12CP) method to allocate demand-related
11                production costs. This approach is consistent not only with the
12                cost-of-service approach FERC typically uses to allocate demand-
13                related production costs reflected in wholesale rate schedules, but
14                also with the assignment of MSS-1 costs (as well as MSS-2
15                transmission costs) to ETI under the ESA. I have calculated test-
16                year 12CP allocation factors for the Texas Retail (94.6208 percent)
17                and Wholesale (5.3792 percent) jurisdictions, and provided them to
18                Cities witness Karl Nalepa for inclusion in his jurisdictional
19                separation study.
20           2.   Reject ETI's adjusted test-year purchased power capacity costs
21                ($276.2 million). Instead, ETI should be allowed to recover no
22                more than approximately ~ ~ million in PPCC. This
23                approximately~ (II million reduction in ETI's proposed rate-
24                year PPCC estimate reflects the following three adjustments:
25                •   -               reduction in costs for Legacy Affiliate Contracts
26                    to reflect more current pricing data.
27                •                    reduction in costs for Other Affiliate Contracts
28                    and Reserve Equalization to reflect more recent contract




                                                                Docket No. 39896
                                                                Dennis W. Goins - Direct
                                                                Page8



                                                                                                 \6
                                                                Revised- Cities' Errata No. 3

 1                             RECOMMENDATIONS

 2   Q.   WHAT DO YOU RECOMMEND ON THE BASIS OF THESE
 3        CONCLUSIONS?

 4   A.   I recommend that the Commission take the following actions regarding the
 5        major issues discussed in my testimony:
6            1.   Reject the AED4CP method used in ETI's jurisdictional separation
 7                study to assign demand-related production costs to its Texas retail
 8                and wholesale jurisdictions.      Instead, the Commission should
 9                require ETI to assign these costs to the wholesale jurisdiction using
10                the 12 coincident peak (12CP) method to allocate demand-related
11                production costs. This approach is consistent not only with the
12                cost-of-service approach FERC typically uses to allocate demand-
13                related production costs reflected in wholesale rate schedules, but
14                also with the assignment of MSS-1 costs (as well as MSS-2
15                transmission costs) to ETI under the BSA. I have calculated test-
16                year 12CP allocation factors for the Texas Retail (94.6208 percent)
17                and Wholesale (5.3792 percent) jurisdictions, and provided them to
18                Cities witness Karl Nalepa for inclusion in his jurisdictional
19                separation study.
20           2.   Reject ETI's adjusted test-year purchased power capacity costs
21                ($276.2 million). Instead, ETI should be allowed to recover no
22                more than approximately $242.9 million in PPCC.                   This
23                approximately $33.3 million reduction in ETI's proposed rate-year
24                PPCC estimate reflects the following three adjustments:
25                •   -               reduction in costs for Legacy Affiliate Contracts
26                    to reflect more current pricing data.
27                •                    reduction in costs for Other Affiliate Contracts
28                    and Reserve Equalization to reflect more recent contract




                                                                Docket No. 39896
                                                                Dennis W. Goins - Direct
                                                                Page8



                                                                                                \1
                                                                         Revised - Cities' Errata No. 3

                           pricing data and Cities recommended adjustment in costs
 2                         related to the EAI WBL contract.6
 3                    •    -               reduction to reflect the effects of load growth on
 4                         rate-year PPCC costs that ETI will recover going forward.
 5              3.    Reject ETI's adjusted test-year MSS-2 costs. ETI's unexplained
 6                                                     in MSS-2 costs relative to test-year
 7                    costs, plus complete uncertainty regarding the magnitude of ETI' s
 8                    post-2012       MSS-2        costs      under      Entergy's       proposed
 9                    divestiture/merger deal with ITC in 2013, make ETI's projected
10                    rate-year MSS-2 costs speculative at best. I recommend setting
11                    ETI's adjusted test-year MSS-2 costs no higher than - -
12                    or                                                               This lower
13                    value reflects ETI's actual 2011 MSS-2 costs                         , plus a
14                                              to reflect the effects of load growth.
15              4.    Require ETI to modify Schedules SHL (Rate Groups A and C) and
16                    TSS to include a minimum 25 percent reduction in monthly fixed
17                                                     charges applicable to street and traffic
18                    lighting fixtures that use LED technology.             Energy charges in
19                    Schedule SHL (Rate Groups D and E) should also be reduced by
20                    25 percent for LED customers. This reduction should partially
21                    reflect the lower cost of operating and maintaining energy-efficient
22                    LED fixtures. In addition, the Commission should require ETI to
23                    eliminate the $50 fee applicable to Rate Groups A and C under
24                    Schedule SHL when an existing light is replaced with a more
25                    efficient light with lower wattage (for example, an LED bulb).
26                    Eliminating this fee will remove a disincentive for customers to
27                    adopt LED fixtures as conservation measures.


     6
       EAi WBL denotes capacity entitlements in several of EAi' s baseload generating units that EAi
     sells at wholesale. Justification for Cities recommended EAi WBL rate-year cost adjustment is
     provided in the direct testimony of Cities witness Karl Nalepa.


                                                                         Docket No. 39896
                                                                         Dennis W. Goins - Direct
                                                                         Page9




                                                                                                          \B
                                                                         Revised- Cities' Errata No. 3


                           pricing data and Cities recommended adjustment in costs
 2                         related to the EAI WBL contract.6
 3
                     •                     reduction to reflect the effects of load growth on
4                          rate-year PPCC costs that ETI will recover going forward.
 5              3.   Reject ETI's adjusted test-year MSS-2 costs. ETI's unexplained
6                                                      in MSS-2 costs relative to test-year
 7                    costs, plus complete uncertainty regarding the magnitude of ETI's
 8                   post-2012        MSS-2        costs      under      Entergy's       proposed
 9                    divestiture/merger deal with ITC in 2013, make ETI's projected
10                   rate-year MSS-2 costs speculative at best. I recommend setting
11                    ETI's adjusted test-year MSS-2 costs no higher than - - -
12                    or                                                               This lower
13                    value reflects ETI's actual 2011 MSS-2 costs                         , plus a
14                                              to reflect the effects of load growth.
15              4.    Require ETI to modify Schedules SHL (Rate Groups A and C) and
16                    TSS to include a minimum 25 percent reduction in monthly fixed
17                    (SHL) and minimum (TSS) charges applicable to street and traffic
18                    lighting fixtures that use LED technology.             Energy charges in
19                    Schedule SHL (Rate Groups D and E) should also be reduced by
20                    25 percent for LED customers. This reduction should partially
21                    reflect the lower cost of operating and maintaining energy-efficient
22                    LED fixtures. In addition, the Commission should require ETI to
23                    eliminate the $50 fee appliqable to Rate Groups A and C under
24                    Schedule SHL when an existing light is replaced with a more
25                    efficient light with lower wattage (for example, an LED bulb).
26                    Eliminating this fee will remove a disincentive for customers to
27                    adopt LED fixtures as conservation measures.


     6
       EAi WBL denotes capacity entitlements in several of EAi' s baseload generating units that EAi
     sells at wholesale. Justification for Cities recommended EAi WBL rate-year cost adjustment is
     provided in the direct testimony of Cities witness Karl Nalepa.


                                                                         Docket No. 39896
                                                                         Dennis W. Goins - Direct
                                                                         Page9




                                                                                                         l~
                                                                           Revised- Cities' Errata No. 3


             and rate-year costs. Next, I adjusted ETI's rate-year estimates of costs for
2            the EAI WBL contract and Reserve Equalization to reflect the adjustment
 3           recommended by Cities witness Karl Nalepa. Finally, I adjusted the rate-
4            year total PPCC estimate to reflect the effects of load growth.                      The
 5           resulting adjusted test-year PPCC by transaction category is shown in
 6           Exhibit DWG-2. 11         As shown in this exhibit, ETI's adjusted test-year
 7           PPCC should be set no higher than $241.a             W        million-or~  Im
 8           million less than ETI's original request.        As I noted earlier, this~ Ila
 9           million reduction in ETI's proposed rate-year PPCC estimate reflects the
10           following three adjustments:
11                    •    -               reduction in costs for Legacy Affiliate Contracts
12                         to reflect more current pricing data.
13                    •                      reduction in costs for Other Affiliate Contracts
14                          and Reserve Equalization to reflect more recent contract
15                         pricing data and Cities recommended adjustment in costs
16                         related to the Cities recommended 50-percent reduction in
17                          adjusted test-year costs for the EAI WBL contract.
18                    •    -                reduction to reflect the effects of load growth.

19   Q.      HOW DID YOU DEVELOP THE LOAD GROWTH ADJUSTMENT
20           YOU APPLIED TO YOUR PPCC ESTIMATE?

21   A.      The development of my recommended                                         load growth
22           adjustment is presented in Exhibit DWG-3. I first reviewed forecasts of
23           ETI's firm load (energy sales and peak demand) from 2011 through 2014.
24           I then calculated the growth in ETI's energy sales and peak demands over
25           different intervals (Exhibit DWG-3, page 1). On the basis of this review, I
26           selected -                as a reasonable estimate of the likely growth in ETI's
27           energy and demand billing determinants from the test year to the rate year.

     11
        Results shown in Exhibit DWG-2 are presented in a format similar to that used by ETI' s witness
     Robert Cooper in Exhibit RRC-1 {HS-revised).

                                                                           Docket No. 39896
                                                                           Dennis W. Goins - Direct
                                                                           Page 18
                                                                         Revised - Cities' Errata No. 3

 1          and rate-year costs. Next, I adjusted ETI's rate-year estimates of costs for
 2          the EAI WBL contract and Reserve Equalization to reflect the adjustment
 3          recommended by Cities witness Karl Nalepa. Finally, I adjusted the rate-
4           year total PPCC estimate to reflect the effects of load growth.                    The
 5          resulting adjusted test-year PPCC by transaction category is shown in
 6          Exhibit DWG-2. 11        As shown in this exhibit, ETI's adjusted test-year
 7          PPCC should be set no higher than $242.9 million-or $33.3 million less
 8          than ETI' s original request. As I noted earlier, this $33 .3 million reduction
 9           in ETI' s proposed rate-year PPCC estimate reflects the following three
10           adjustments:
11                   •    -               reduction in costs for Legacy Affiliate Contracts
12                        to reflect more current pricing data.
13
                     •                      reduction in costs for Other Affiliate Contracts
14                         and Reserve Equalization to reflect more recent contract
15                        pricing data and Cities recommended adjustment in costs
16                         related to the Cities recommended 50-percent reduction in
17                         adjusted test-year costs for the EAI WBL contract.
18                   •                     reduction to reflect the effects of load growth.

19   Q.      HOW DID YOU DEVELOP THE LOAD GROWTH ADJUSTMENT
20           YOU APPLIED TO YOUR PPCC ESTIMATE?

21   A.      The development of my recommended                                      load growth
22           adjustment is presented in Exhibit DWG-3. I first reviewed forecasts of
23           ETI's firm load (energy sales and peak demand) from 2011 through 2014.
24           I then calculated the growth in ETI's energy sales and peak demands over
25           different intervals (Exhibit DWG-3, page 1). On the basis of this review, I
26           s e l e c t e d - as a reasonable estimate of the likely growth in ETI's
27           energy and demand billing determinants from the test year to the rate year.

     11
      Results shown in Exhibit DWG-2.are presented in a fonnat similar to that used by ETI's witness
     Robert Cooper in Exhibit RRC-1 (HS-revised).


                                                                         Docket No. 39896
                                                                         Dennis W. Goins - Direct
                                                                         Page 18
                                                                 Revised- Cities' Errata No. 3


          I next estimated ETI's rate-year energy billing units, and derived an
 2        average cost per billing unit (Exhibit DWG-3, page 2) for the estimated
 3        rate-year PPCC shown in column (c) of Exhibit DWG-2. The product of
 4        this average rate-year PPCC and ETI's test-year kWh billing units equals
 5        the adjusted test-year PPCC that ETI should be allowed to include in base
 6        rates.

 7   Q.   IS   YOUR       RECOMMENDED             $241.J    em         MILLION        IN
 8        ADJUSTED TEST-YEAR PPCC A REASONABLE AND FAIR
 9        ESTIMATE OF COSTS THAT ETI IS LIKELY TO INCUR IN THE
10        RATE YEAR?

11   A.   Yes. My estimate mitigates two problems that cause ETI to overstate its
12        rate-year PPCC-its failure to adjust rate-year projections to reflect load
13        growth, and the use of dated transaction price proxies. In addition, my
14        estimate reflects witness Nalepa's recommended cost adjustments related
15        to the EAI WBL contract.


16                                   MSS-2 COSTS

17   Q.   WHAT ARE MSS-2 COSTS?

18   A.   Under the ESA's Service Schedule MSS-2, the EOCs share cost
19        responsibility for the Entergy transmission system much like they share
20        cost responsibility for generating resources under Service Schedule MSS-
21        1.   Each month an EOC receives       -'O!Il!t«m
22
23        EOC's level of transmission investment relative to
24        total System transmission investments, its hHtfi re~011sibili-ty ratie, and the
25        tifJD    average                                       cost=of total System
26        investments.




                                                                Docket No. 39896
                                                                Dennis W. Goins - Direct
                                                                Page 19
                                                              Revised - Cities' Errata No. 3


          I next estimated ETI's rate-year energy billing units, and derived an
2         average cost per billing unit (Exhibit DWG-3, page 2) for the estimated
3         rate-year PPCC shown in column (c) of Exhibit DWG-2. The product of
4         this average rate-year PPCC and ETI's test-year kWh billing units equals
5         the adjusted test-year PPCC that ETI should be allowed to include in base
6         rates.

 7   Q.   IS YOUR RECOMMENDED $242.9 MILLION IN ADJUSTED
 8        TEST-YEAR PPCC A REASONABLE AND FAIR ESTIMATE OF
 9        COSTS THAT ETI IS LIKELY TO INCUR IN THE RATE YEAR?

10   A.   Yes. My estimate mitigates two problems that cause ETI to overstate its
11        rate-year PPCC-its failure to adjust rate-year projections to reflect load
12        growth, and the use of dated transaction price proxies. In addition, my
13        estimate reflects witness Nalepa's recommended cost adjustments related
14        to the EAI WBL contract.


15                                   MSS-2 COSTS

16   Q.   WHAT ARE MSS-2 COSTS?

17   A.   Under the ESA's Service Schedule MSS-2, the EOCs share cost
18        responsibility for the Entergy transmission system much like they share
19        cost responsibility for generating resources under Service Schedule MSS-
20        1. Each month an EOC receives an MSS-2 transmission equalization
21        payment or bill that reflects the EOC's level of transmission investment
22        relative to its responsibility for total System transmission investment, and
23        the System average annual transmission ownership.




                                                              Docket No. 39896
                                                              Dennis W. Goins - Direct
                                                              Page 19
               SOAH DOCKET NO. XXX-XX-XXXX
                 PUC DOCKET NO. 39896




                                                                    •
APPLICATION OF ENTERGY TEXAS,         §
INC. FOR AUTHORITY TO CHANGE          §   BEFORE THE STATE OFFICE
RATES, RECONCILE FUEL COSTS,          §            OF
AND OBTAIN DEFERRED                   §   ADMINISTRATIVE HEARINGS
ACCOUNTING TREATMENT                  §




            DIRECT TESTIMONY AND EXHIBITS

                              OF

                      KARL J. NALEPA



                       ON BEHALF OF

          CITIES SERVED BY ENTERGY TEXAS, INC.




                       MARCH 27, 2012


               REDACTED PUBLIC VERSION



               ReSolved Energy Consulting, LLC
               11044 Research Blvd., Suite D-230
                     Austin, Texas 78759
Blank Page
                                       DIRECT TESTIMONY OF
                                          KARL J. NALEPA

                                         TABLE OF CONTENTS




I.     INTRODUCTION AND QUALIFICATIONS .................................................................. 2
II.    PURPOSE AND SCOPE .................................................................................................... 4
III.   SUMMARY AND RECOMMENDATIONS ..................................................................... 4
IV.    COST OF SERVICE ADJUSTMENTS ............................................................................. 7
       A.   PURCHASED CAP A CITY COSTS ...................................................................... 7
       B.   NATURAL GAS STORAGE ............................................................................... 18
       C.   COAL INVENTORIES ........................................................................................ 27
       D.   RENEW ABLE ENERGY CREDIT RIDER ........................................................ 30
       E.   COST OF SERVICE MODEL ............................................................................. 32
       F.   COST ALLOCATION .......................................................................................... 34
V.     OVERVIEW OF ETI'S FUEL COSTS ............................................................................ 37
VI.    FUEL COST ADJUSTMENTS ........................................................................................ 38
       A.   NATURAL GAS STORAGE COSTS .................................................................. 38
       B.   LOSS FACTORS .................................................................................................. 43



APPENDICES

APPENDIX A - Statement of Qualifications
APPENDIX B -Previously Filed Testimony




DIRECT TESTIMONY                                                                                              NALEPA
Blank Page
                           DIRECT TESTIMONY OF
                              KARL J. NALEPA

                            TABLE OF CONTENTS

ATTACHMENTS

KJN-1       Cities' Cost of Service Model
KJN-2       Fuel Reconciliation Adjustments
KJN-3       Test Year Capacity Costs
KJN-4       Rate Year Capacity Costs




DIRECT TESTIMONY                      2          NALEPA
Blank Page
                                    SOAH Docket No. XXX-XX-XXXX
                                      PUC Docket No. 37744


     APPLICATION OF ENTERGY                         §          BEFORE THE
     TEXAS, INC. FOR AUTHORITY                      §        STATE OFFICE OF
     TO CHANGE RATES AND TO                         §    ADMINISTRATIVE HEARINGS
     RECONCILE FUEL COSTS                           §
 2
 3                                      DIRECT TESTIMONY OF
 4                                         KARL J. NALEPA

 5                       I.      INTRODUCTION AND QUALIFICATIONS

 6

 7   Q.    PLEASE STATE YOUR NAME, OCCUPATION, AND BUSINESS ADDRESS.

 8   A.    My name is Karl J. Nalepa. I am the President of ReSolved Energy Consulting, LLC

 9         ("REC"), formerly R.J. Covington Consulting, LLC. REC is an independent utility

10         consulting company. My business address is 11044 Research Blvd., Suite D-230,

11         Austin, Texas 78759.

12

13   Q.    ON WHOSE BEHALF ARE YOU PRESENTING TESTIMONY IN THIS

14         PROCEEDING?

15   A.    I am presenting testimony on behalf of Cities served by Entergy Texas, Inc.

16         ("Cities").

17

18   Q.    PLEASE             OUTLINE    YOUR   EDUCATIONAL       AND      PROFESSIONAL

19         BACKGROUND.

20   A.   I hold a Bachelor of Science degree in Mineral Economics and a Master of Science

21         degree in Petroleum Engineering, and am a certified mediator.    My professional



     DIRECT TESTIMONY                           2                                  NALEPA
 1                                      II.      PURPOSE AND SCOPE

 2

 3   Q.            WHAT IS THE PURPOSE AND SCOPE OF YOUR TESTIMONY IN THIS

 4                 PROCEEDING?

 5   A.            The purpose and scope of my testimony is twofold: First, to review certain issues

 6                 ranging from purchase power to expense and rate base items and if necessary to

 7                 present certain recommendations regarding Entergy Texas, Inc.' s ("ETI") proposed

 8                 cost of service, based on a test year ending June 30, 2011. 1 Second, to review fuel

 9                 related issues and if necessary to present recommendations regarding ETI' s request to

10                 reconcile its fuel costs incurred during the period July 1, 2009 through June 30, 2011

11                 (the "Reconciliation Period").2 Third, I sponsor the cost of service for the Cities case

12                 and propose an allocation of any increase in the event Cities recommendation to

13                 maintain the existing rates is not approved. Within my testimony, references to "ETI"

14                 or the "Company" may be used interchangeably.

15


16                           III.      SUMMARY AND RECOMMENDATIONS

17

18   Q.            PLEASE       SUMMARIZE            YOUR         RECOMMENDATIONS                     IN      THIS

19                 PROCEEDING?

20             A.         I make the following recommendations regarding the Company's proposed

21             rate request:


     1
      Statement of Intent and Application for Authority to Change Rates and to Reconcile Fuel Costs, p. 4.
     2Jd., p. I.



     DIRECT TESTIMONY                                     4                                                  NALEPA
 1         1. ETI is requesting purchased power capacity expense of $275,809,485. I propose
 2            several alternative adjustments to the MSS-4 and 3rd party purchase components
 3            of ETis request for purchased power capacity expense to better reflect the known
 4            and measurable nature of these costs as well as all attendant impacts. My
 5            recommendation is that the Commission approves purchased power capacity
 6            expense of $236,838,634, a reduction of $38,970,851 to the ETI requested
 7            capacity cost amount. This adjustment is presented as an alternative to Dr. Goins
 8            purchase power recomn1endation-should the ALJ s and the Commission adopt
 9            my alternative for adjusting the Company's purchase power request.
10
11         2. The Company operates the Spindletop gas storage facility to provide gas supply
12            reliability and flexibility for ETI's Sabine and Lewis Creek power plants. The
13            Company has acknowledged there are less costly options to provide this same
14            supply reliability and flexibility in gas supply. Eliminating the Spindletop facility
15            and selecting the less costly and readily available alternative will save customers
16            $ 11.4 million per year without diminishing fuel supply flexibility or reliability. It
17            would be imprudent to continue with the Company's Spindletop alternative. As
18            such, I recommend that the facility be removed from rates and from regulated
19            service if necessary. Total base rate costs to be removed are $7,653,293. In
20            addition, the Commission should exclude as an eligible fuel expense the variable
21            non-gas operating costs of Spindletop, which during the test year were
22            $5,424,895.     The variable non-gas operating costs of Spindletop for the
23            reconciliation period will be addressed in the fuel reconciliation portion of my
24            testimony.
25
26         3. ETI is requesting an average test year coal inventory value of $6,740,528 at
27            Nelson 6. This is equivalent to 66 days of inventory at full bum. However, the
28            Company has established that an average target inventory of 43 days at Nelson 6
29            is sufficient to meet its reliability requirements. I recommend that the 43 day coal
30            inventory level be included in rate base, resulting in a revised inventory level for
31            Nelson 6 of $4,381,988 and reducing the Company's requested inventory level by
32            $2,358,540.
33
34         4. ETI is requesting approval of a Renewable Energy Credit Rider ("REC") in this
35            case. It proposes to shift recovery of its renewable energy credit costs from base
36            rates to the REC Rider. The Commission should not permit the Company to single
37            out REC costs from base rates. ETI has presented no evidence that suggests the
38            costs should be treated differently than they are now. As a result, I recommend the
39            adjusted test year amount of $633,985 be included in base rates for REC costs.
40
41         5. I am sponsoring Cities' cost of service model based on the Company's model, and
42            have compiled the adjustments to the Company's proposed revenue requirement
43            recommended by each of the Cities' experts The Cities' proposed revenue
44            requirement is $1,367.5 million, which is $126.0 million less than the Company's
45            proposed revenue requirement.
46



     DIRECT TESTIMONY                           5                                          NALEPA
 1            In addition, I make the following recommendations regarding the Company's

 2            reconcilable costs:

 3            6. During the reconciliation period, the Spindletop gas storage facility did not provide
 4                any increased supply reliability or flexibility relative to other options available to
 5                ETI at the Sabine and Lewis Creek Generating Stations. Compared to other
 /:;.
 v                supply options available to the Company, the Spindletop facility cost customers
 7                $11.4 million more per year for the same supply reliability and flexibility. It
 8                would not be prudent to continue charging customers for this unreasonable level
 9                of expense. I adjusted reconcilable storage costs to reflect the average cost of
10                transportation to Sabine plus call options on supply as a reasonable alternative to
11                storage. This reduces storage related reconcilable costs by $6,595,290.
12
13            7. ETI's proposed tariff Schedule FF Fixed Fuel Factor includes loss multipliers by
14               voltage level which were calculated in a study based on the 12 months ending
15               December 3 l, 1997. I adjust line loss factors to reflect current losses, reducing
16               fuel expenses properly allocable to Texas retail customers by $3,981,271.
17

18      Q.    WHAT        IS        THE    TOTAL        DOLLAR         AMOUNT           OF      YOUR

19            RECOMMENDATIONS?

20      A.    My recommended adjustments to the Company's proposed base rate or non fuel cost

21            of service are summarized in Table 1. I recommend a total adjustment to reconcilable

22            fuel costs of $10,576,561 (consisting of $6,595,290 in storage costs and $3,981,271 in

23            line loss costs). This adjustment is summarized on a monthly basis in Attachment

24            KJN-2.

25                                          TABLE 1
                          Adjustment                  Rate Base              Expense
                    Nelson 6 Coal Inventory          ($2,358,540)
                    Spindletop Gas Storage          ($48,301,624)          ($2,090,116)
                Renewable Energy Credit Rider     Deny Rider - include $633,985 in cost of
                                                                   service
              Purchased Power Capacity EAI WBL
                             Total                  ($50,660, 164)




        DIRECT TESTIMONY                            6                                         NALEPA
           It should be noted that the load growth related third party Purchased Power Capacity

           adjustment included in the $38,970,851 recommendation above is presented as an

           alternative to Dr. Goins purchase power capacity recommendation and is not part of

           the total adjustment shown in Table 1. Another portion of my $38,970,851 purchase

           power adjustment related to the Entergy Arkansas Inc. or EAI WBL contract is

           proposed to be included in the cost of service and is part of Dr. Goins' analysis. The

           two components of the purchase power adjustment are discussed in detail below.




 1                      IV.       COST OF SERVICE ADJUSTMENTS

 2

 3   Q.    PLEASE DESCRIBE THE COST OF SERVICE ADJUSTMENTS YOU ARE

 4         RECOMMENDING.

 5   A.    I am recommending the following cost of service adjustments:

 6         1. Purchased Capacity Costs;
 7         2. Natural Gas Storage;
 8         3. Coal Inventories;
 9         4. Renewable Energy Credit Rider;
10         5. Cost of Service Model quantification of adjustments
11               provided by other Cities witnesses; and
12         6. Customer Class Allocation
13
14
15                        A.      PURCHASED CAPA CITY COSTS

16   Q.    WHAT ISSUE ARE YOU ADDRESSING IN THIS SECTION OF YOUR

17         TESTIMONY?

18   A.    In this section of my testimony I develop the MSS-4 and third party purchased power

19         capacity costs for inclusion in base rates.




     DIRECT TESTIMONY                             7                                     NALEPA
 1

 2   Q.         DID THE COMPANY ORIGINALLY REQUEST A RECONCILABLE

 3              PURCHASED POWER RIDER?

 4   A.         Yes.     Originally, ETI filed this case requesting a total purchase power amount

 5              (including MSS-1, MSS-4, and third party capacity purchases) of $276,242,239 3

 6              which would be part of a Purchased Power Rider ("PPR") and subject to periodic

 7              reconciliation. 4 Thus, the fact that the Company's forecast and estimate of future

 8              purchase power levels of $276,242,239 could be overstated was of little concern to

 9              ETI because under the original proposal, such amounts would be subject to periodic

10              reconciliation and true-up to actual levels.

11                       Now that the Commission has ruled that a PPR will not be authorized in this

12              proceeding, the Company has requested that the full estimated purchase power

13              amount of $276,242,239 be included in base rates. The problem with the Company's

14              proposal to include the entire $276,242,239 estimate in base rates is that there is no

15              future reconciliation for excess purchase power estimates.                 Furthermore, the

16              Company has mixed and matched apples and oranges by including a forecast of rate

17              year purchase power costs with test year end billing determinates.               Under the

18              Company's approach of mixing estimated rate year costs with test year billing units,

19              there is a failure to recognize customer growth and increased sales revenue-thus

20              overstating the revenue requirement.              And while it is true that a reconciliation

21              mechanism, such as proposed by ETI, may alleviate any excess earnings caused by an

22              overestimate of capacity costs or a mismatch of test year costs to rate year billing

     3
         ETI Schedule Q-8.8, ETI Proposed Tariffs at page 44.5.
     4
         Direct Testimony of Phillip May, p. 5-6.


     DIRECT TESTIMONY                                      8                                        NALEPA
 1            determinates, ETI should not be permitted to overestimate capacity costs to

 2            artificially create its own need for a reconcilable PPR.

 3

 4   Q.       PLEASE PROVIDE AN EXAMPLE DEMONSTRATING THE BIAS IN ETI'S

 5            APPROACH AND THE PROPER METHOD OF ADJUSTING RA TE YEAR

 6            PURCHASED POWER COSTS FOR TEST YEAR CAPACITY LEVELS?

 7   A.       Assume that a utility has one cost-purchase power capacity-and a test year

 8            purchase power cost of $100.00 for 100 kW of capacity to serve test year load of 100

 9            kW (including reserves). The test year rate would be $1.00 /kW shown in Table 2:

10                                               TABLE2
                                                                         Test Year

                  Total Capacity Costs                                    $100.00

                  Capacity to Serve Load                                  lOOkW

                  Capacity Cost Embedded in Rates                        $1.00 /kW

11

12           Now, if during some future period this utility needs 50 more kW for an increase in

13            load and it can acquire the 50 kW of capacity for $50, then the cost of capacity

14           embedded in rates--$1 /kW of supply-would be sufficient to recover the additional

15           costs. This is demonstrated in Table 3 below:

16                                               TABLE 3
                                                             Test Year               Future Year

          Total Capacity Costs                                $100.00                 $150.00

          Capacity to Serve Load                              100 kW                  150 kW

          Cost of Capacity                                   $1.00 /kW               $1.00 /kW

          Capacity Cost Embedded in Rates                    $1.00 /kW               $1.00 /kW

17



     DIRECT TESTIMONY                               9                                            NALEPA
               Under the above scenario, no change in the rate would be necessary to recover the

 2             additional costs of acquiring the additional kW of capacity. But, if the added 50 kW

 3             cost $1.50 /kW, or $75.00, the utility would need an increase in rates of $0.1667 to

 4             recover the incremental costs, as shown in Table 4:

 5                                               TABLE4
                                                             Test Year          Future Year

           Total Capacity Costs                              $100.00              $175.00

           Capacity to Serve Load                            100 kW               150kW

           Cost of Capacity                                 $1.00 /kW           $1.1667 /kW
                                                                                                 I


          I Capacity Cost Embedded in Rates                 $1.00 /kW            $1.00 /kW

                                                                 Difference     $0.1667 /kW

 6

 7             Under the Company's approach in this case, ETI would ignore the fact that it already

 8             collects $1.00 of revenues under the existing rate and requests the full $1.50

 9             incremental increase for the added 50 kW. This would lead to an over-collection of

10            revenues by the Company and would result in excess profits for shareholders.

11

12   Q.       DO YOU AGREE WITH THE COMPANY'S REQUESTED AMOUNT?

13   A.       No, the $276,242,239 purchased power capacity amount is not reasonable and is

14            excessive.

15

16   Q.       WHY IS THE REQUESTED AMOUNT NOT REASONABLE?

17   A.       I compared the requested purchased power capacity expenses to the test year amount

18            in this proceeding. Table 5 summarizes these values:




     DIRECT TESTIMONY                              10                                        NALEPA
                                                         TABLE 5
                                      Source             Test Year      Rate Year

                                      MSS-1              $25,461,352
                                      MSS-4             $189,032,441
                                    Third Party          $30,818,009
                                       Total            $245,311,802   $276,242,239
 1

 2              ETI' s request is almost $31 million higher than its test year capacity costs.

 3

 4   Q.         WHAT HAS CAUSED THIS DRAMATIC INCREASE IN COSTS?

 5   A.         While the MSS-1 and MSS-4 rate year requests are actually less than the test year

 6              amount, the rate year third party purchases are more than •         million higher than the

 7              test year. This increase is mostly attributable to three new purchased power

 8              agreements. These are with Exelon-Frontier, which added 150 MW to its existing 150

 9              MW contract beginning May 2011, Calpine-Carville, which will add 243 MW (50%

10              of 485 MW) for a ten year term beginning June 2012, and 225 MW with Sam

11              Rayburn Municipal Power Agency ("SRMP A") for a 25 year term beginning

12              December 2011. 5

13

14   Q.         HOW DOES THE COMP ANY'S PROPOSAL ADVERSELY AFFECT

15              CUSTOMERS?

16   A.         The Company is contracting for capacity resources to meet future demand, but is

17              intending to recover these costs from current customers. As discussed earlier,

18              dividing projected rate year costs by test year adjusted billing determinants results in



     5
         Direct Testimony of Robert Cooper, p. 16-17.


     DlRECT TESTIMONY                                     11                                      NALEPA
 1               a violation of the matching principal of ratemaking. Commission Rules require that

 2               only the electric utility's historical test year expenses as adjusted for known and
                                                                                           6
 3               measurable changes will be considered in allowable expenses.                  Post test year

 4               adjustments for known and measurable rate base additions to historical test year data

 5               will be considered in part only where the attendant impacts on all aspects of a utility's

 6               operations (including but not limited to, revenue, expenses and invested capital) can
                                                                                           7
 7               with reasonable certainty be identified, quantified and matched. And while this

 8               section of the Rule refers to rate base additions, the concept of matching a post test

 9               year adjustment with its attendant impacts applies to post test year expense

10               adjustments as well. In fact, prior versions of the Substantive Rules did require this:

11                                                                                                   to
12                                                                                             revenue,
13
14
15
16
17               The development of the proposed purchased capacity costs should correspond with

18               the billing determinants used to calculate the rates.

19

20   Q.          WHAT AMOUNT                 OF CAPACITY COSTS DO YOU PROPOSE BE

21               INCLUDED IN RATES?

22   A.          I propose that third party capacity costs be calculated using the average cost of the

23               Company's third party rate year capacity applied to the test year end capacity. In this

24               way, the increased cost of the new resources is recognized, but current demand is

     6
         Rule §25.231 (b ).
     7
         Rule §25.23 l(c)(2)(F).
     8
         Docket No. 1175,                    Texas Urilities Electric    For
                              General Counsel Into The                   Texas Utilities


     DIRECT TESTIMONY                                       12                                        NALEPA
 l         better matched to current resources. My Attachments KJN-3 and KJN-4 detail the test

 2         year and rate year capacity and capacity costs. The Company's proposed rate year

 3         capacity cost o f - divided by the total capacity of 12,834 annual MW (or

 4         an average 1,070 kW/mo) yields an average rate of                    . This compares to

 5         the test year cost of $5.08 /kW/mo. Multiplying the test year end third party capacity

 6         of 671 MW (or 8,052 annual MW) by the average rate year cost yields third party

 7                                          , which is an increase o f - over the test year

 8         but a reduction of I           111 to the Company's proposed third party capacity costs.
 9         These calculations are summarized in Table 6.

10                                              TABLE 6
                                   Third Party Capacity Cost Calculation
                                  Rate Year                                  Proposed
                Annual             Average       Average       Test Year      Annual
                Capacity           Monthly       Monthly         End         Capacity
                 Cost              Capacity        Rate        Capacity        Cost
                                  1,070 MW                     671 MW
11

12   Q.    DO YOU MAKE ANY ADJUSTMENTS TO ETI'S PROPOSED MSS-4

13         CAPACITY COSTS?

14   A.    Yes. I recommend an adjustment to the EAI WBL contract expense, included in its

15         MSS-4 tariff.

16

17   Q.    PLEASE DESCRIBE THE EAi WBL CONTRACT.

18   A.    The contract is with affiliate Entergy Arkansas, Inc. for wholesale baseload resources

19         ("EAi WBL"), selected as a result of Entergy's July 2009 Baseload RFP. ETI was

20         allocated 31. 7% of the 336 MW capacity associated with the units that make-up this




     DIRECT TESTIMONY                             13                                      NALEPA
 1               WBL resource. 9 It consists of a portion of EAI's nuclear and coal generating capacity

 2               as summarized in Table 7: 10

 3                                                       TABLE 7
                                       Resource                      Total
                                                             ~+--~
                                                                    Capacity.-"---1~---'




                           Total                                        3,455          336
 4

 5   Q.          WHAT IS YOUR ADJUSTMENT?

 6   A.          The original term of the EAI WBL contract was for three years ending December 31,
                                                                                                     11
 7               2012.

 8               My adjustment recognizes that the contract will expire only 18 months after the rates

 9               are expected go into effect in this proceeding. Assuming that ETI' s rates will be in

10               effect for three years, I recommend that the EAI WBL contract be "normalized" over

]1               the three year period.

12




     9
          Docket No. 37744, Direct Testimony of Robert Cooper, p. 27.
     10
          Jd., WP/RRC Testimony 2 (Highly Sensitive)
     11
          ETI Response to TIEC 5-1 (Highly Sensitive).


     DIRECT TESTIMONY                                      14                                 NALEPA
 1   Q.         WHAT IS YOUR BASIS FOR ASSUMING THAT ETI'S RATES WILL BE IN

 2              EFFECT FOR THREE YEARS?

 3   A.         Three years is a common assumption for the time period between rate changes. For

 4              example, in this proceeding, ETI proposes to amortize over three years its expected

 5              MISO transition costs. 12

 6

 7   Q.         PLEASE        EXPLAIN         THE      COMPANY'S     AMORTIZATION            OF    MISO

 8              TRANSITION COSTS.

 9   A.         ETI is proposing two adjustments to rates in this proceeding regarding its MISO

10              transition costs. First, it seeks to defer expenses incurred after January 1, 2012 related

11              to its proposed transition to membership in the MISO regional transmission

12              organization. Its request for deferral was filed in Docket No. 39741, but was

13              subsequently consolidated with this proceeding. 13 Second, if the Company is not

14              granted deferred accounting, then it proposes to amortize its projected MISO

15              transition expenses of $12 million over 3 years and recover the amount of $4 million

16              annually in account 575100. 14

17

18   Q.         HOW DO YOU NORMALIZE THE EAi WBL CONTRACT?

19   A.         The rates in this proceeding are expected to be effective July 2012, based on the

20              agreed procedural schedule. ETI has projected rate year EAI WBL contract expense




     12
          Direct Testimony of Michael Considine, p. 21-22.
     13
          Docket No. 39741, SOAH Order No. 2.
     14
          WP P AJ16.20-16.23L.


     DIRECT TESTIMONY                                        15                                   NALEPA
                                    15                                                          16
 1               of-,                    but has subsequently revised this amount to                 Since

 2               the contract will expire half way through the expected period that the rates will be

 3               effect, I recommend that only half the contract expense be included in rates. This

 4               ensures that the Company collects in rates only the capacity expenses that it actually

 5               incurs. Therefore, I recommend the amount of capacity expense for the EAI WBL

 6                                                                   I   ,   a reduction of -   from the

 7               Company's requested amount. I have provided this adjustment to Dr. Goins for

 8               inclusion in his overall purchase power capacity adjustment.

 9

10   Q.          WHAT ARE MSS-1 PAYMENTS?

11   A.          Service Schedule MSS-1 (called "Reserve Equalization" in the Entergy System

12               Agreement) prescribes a method for sharing some of the fixed costs of generating

13               capability among Entergy Operating Companies. Some Operating Companies own

14               more than their share of the System's total capability relative to their load, and thus

15               are "long" or own more than their share of System reserves. Other Companies own

16               less than their share, or are "short." A short company makes a payment for the MW

17               by which it is short. The payments are computed monthly by multiplying the

18               company's MW shortfall times a $/MW rate for the cost of owmng reserve

19                    ·1· 17
                 capab11ty.

20




     15
          Direct Testimony of Robert Cooper, Exhibit RRC-1 (Highly Sensitive).
     16
          Jd., Revised Exhibit RRC-1 (Highly Sensitive).
     17
          Direct Testimony of Patrick Cicio, p. 11-15.


     DIRECT TESTIMONY                                      16                                   NALEPA
        Q.         DO YOU MAKE ANY ADJUSTMENTS TO ETI'S PROPOSED MSS-1

 2                 CAPACITY COSTS?
 ,..,
 .)     A.         No, I recommend the Company's updated level of MSS-1 capacity costs of
                                   18
 4                 - ,                   which was revised from the Company's original request of

 5                                l . 19 I provided this updated MSS-1 value to Dr. Goins for use in his

 6                 purchase power analysis in this case.

 7

 8      Q.         WHAT IS YOUR TOTAL PURCHASED CAPACITY RECOMMENDATION?

 9      A.         I recommend total purchased capacity expense of $236,838,634, which is a reduction

10                 of $38,970,851 from the Company's request, as summarized in Table 8.

                                                          TABLE 8
                                        Source                                    City

                                        MSS-1
                                        MSS-4

                                        Total           $275,809,485           $236,838,634



11      Q.         DO YOU HAVE ANY OTHER COMMENTS RELATED TO ETl'S

12                 PURCHASED CAPACITY REQUEST?

13      A.         Yes. While Cities' are opposed to a purchase power rider as proposed by ETI, to the

14                 extent that this proceeding is used to establish a baseline for purchased capacity costs,

15                 any baseline should reflect the unit cost of capacity, i.e., $/kW, rather than simply

16                 total dollars. As I discussed earlier in my testimony, the unit cost provides a more

17                 accurate measure of the level of capacity costs required by the utility.          In my

        18
             Direct Testimony of Robert Cooper, Revised Exhibit RRC-1 (Highly Sensitive).
        19
             Id., Exhibit RRC-1 (Highly Sensitive).


        DIRECT TESTIMONY                                     17                                    NALEPA
 1         Attachments KJN-3 and KJN-4, the total dollars as well as the total kW purchased

 2         power capacity supply and owned generation is provided.



 3                            B.     NATURAL GAS STORAGE

 4   Q.    WHY ARE YOU ADDRESSING NATURAL GAS STORAGE COSTS?

 5   A.    As I discuss in the following section of my testimony, based on the Company's filed

 6         or claimed costs the SpindletopGas Storage Facility ("Spindletop") costs $13,078, 188

 7         per year to operate.    ETI can achieve the same supply reliability and flexibility

 8         benefits derived from Spindletop through other alternative gas supply options at an

 9         alternative cost of $ 1, 724,659 per year.     Thus, eliminating Spindletop saves

10         customers $11,353,529 per year.      It would be imprudent to continue including

11         Spindletop in rates.

12

13   Q.   WHAT IS THE ISSUE WITH THE COMPANY'S NATURAL GAS STORAGE

14        FACILITY?

15   A.   The Spindletop facility costs customers approximately $13,078, 188 annually. The

16        costs are detailed in Table 9:

17




     DIRECT TESTIMONY                          18                                      NALEPA
l                                               TABLE 9
                                     SPINDLETOP GAS STORAGE FACILITY
                                           TOT AL COST IMP ACT

             Component                                  Amount                  Source

         Return Component
            Net Plant                                        $5,974,070       Cities 7-73
            Gas lnventorJI                                $42,327,554        Schedule E-2.3
               Rate Base                                  $48,301,624

         Rate of Return
            Long Tenn Debt                                0.03376777         Schedule K-1
            Common Equity                                 0.05291520         Schedule K-1
              Tax Adjustment                                 1.53846154
            Adjusted Common Equity                        0.08140800
              Adjusted Rate of Return                     0.11517577

         Return                                              $5,563, 177
         Depreciation Expense                                 $309,751        Cities 7-74
         Other Taxes
              Ad Valorem Taxes                               $1,780,365       Cities 7-72

         Total Base Rate Costs                               $7,653,293


         Spindletop Storage
         Total Eligible Fuel Costs                           $5,424,895     Exhibit KDM-13

         Total Annual Cost                                $13,078, 188




2   Q.      ARE THESE CHARGES TO CUSTOMERS REASONABLE OR JUSTIFIED?

3   A.      No. Spindletop costs customers about $13 million during the test year. However, the

4           facility is not used to provide any necessary services that are not provided by other

5           gas transportation contracts or balancing agreements of ETI. Table 10 provides a cost

6           benefit analysis comparing the costs ETI would incur to acquire the same services

7           that were provided by the Spindletop facility.

8
9


    DIRECT TESTIMONY                             19                                         NALEPA
                                                                 TABLElO
                Storage           Base Rate          Variable         Total      Alternative                   Total
              Withdrawals/         Storage           Storage         Storage      Transport       Call     Alternative     Net Cost
 Month        Adjustments           Costs             Costs           Costs          Costs       Options       Costs        (e h)
    a              b                  e                 d               e              f            g            h             I
  7/10         1,248,176          $637,774          $ 769,753      $1,407,527     $ 224,672     $ 26,250    $ 250,922     $1,156,605
  8/10         1,000,525          $637,774          $ 112,203       $ 749,977     $ 180,095     $ 26,250    $ 206,345      $543,632
 9/10           715,348           $637,774          $ 419,413      $ 1,057,187    $ 128,763     $ 26,250    $ 155,013      $902,174
 10/10          831,584      I    $637,774     I    $ 449,539      $ 1,087,313    $ 149,685        $0       $ 149,685      $937,628 ·-
 11/10          413,276           $637,774          $ 433,368      $ 1,071,142     $ 74,390        $0        $ 74,390      $996,752
 12/10          288,652           $637,774          $ 130,669       $ 768,443      $51,957         $0        $ 51,957      $716,486
  1/11          411,742           $637,774          $ 338,323       $ 976,097      $74,114      $ 26,250    $ 100,364      $875,733
 2/11           601,934           $637,774          $ 612,537      $ 1,250,311    $ 108,348     $ 26,250    $ 134,598     $1,115,713
 3/11           580,673           $637,774          $ 667,727      $ 1,305,501    $ 104,521     $ 26,250    $ 130,771     $1,174,730
 4/11           766,831           $637,774          $ 606,674      $ 1,244,448    $ 138,030        $0       $ 138,030     $1,106,418
 5/11           827,689           $637,774          $ 574,684      $ 1,212,458    $ 148,984        $0       $ 148,984     $1,063,474
 6/11           874.174           $637,774          $310,005        $ 947,779     $ 157,351     $ 26.250    $ 183,601      $764,178
 Total         8,560,604         $ 7,653,293       $ 5,424,895    $ 13,078,188   $ 1,540,909   $ 183,750   $ 1,724,659   $11,353,529
 2

 3              As shown above, ETI' s charges to customers associated with the Spindletop gas

 4              storage facility are about $ 11.4 million more, annually, than the cost of providing

 5              comparable services. Even so, I recommend that the full amount of costs associated

 6              with the Spindletop facility be removed from cost of service because ETI does not use

 7              or need the Spindletop facility, as more fully detailed below.                        No other Entergy

 8              Operating Company owns or leases its own gas storage facility 20 and the supply

 9              reliability and swing flexibility provided by Spindletop is obtained under other

10              existing gas supply and transportation contracts at a much lower cost. Moreover,

11              other Entergy Operating Companies do not even contract for the transportation and

12              balancing agreements ETI acquires for its Texas gas generating facilities.

13




     20
          Response to Cities 18-15.


     DIRECT TESTIMONY                                             20                                              NALEPA
     Q.         WHAT WAS THE STATED PURPOSE OF THE SPINDLETOP GAS

 2              STORAGE FACILITY WHEN IT WAS ORIGINALLY PLACED IN

 3              SERVICE?

 4   A.         Gulf States Utilities ("GSU"), the predecessor to ETI, first raised the issue of the

 5              benefits of the gas storage facility in Docket No. 10894. In that proceeding, GSU

 6              alleged that the purpose of using the Spindletop Facility was to provide the

 7              maximum/minimum swing requirements presently supplied by GSU's existing

 8              suppliers. GSU further stated that the gas storage facility provided the same benefits

 9              to customers, but at a much lower cost:

10                      There is only one basic difference between the SGT agreement and
11                      other transportation agreements-the SGT agreement is a far better
12                      deal for ratepayers. . . . . As a result of the SGT arrangement,
13                      ratepayers will receive transportation and swing services at a very
14                      reasonable price in the near term and at an extremely low price
15                      following payoff of the facility costs. These benefits are reflected in
16                      the Company's cost benefit analysis, which shows net savings ranging
17                      from $10 to $15 million per year through year eight and then
18                      increasing to approximately $25 million per year thereafter, following
19                      payoff of the facility. 21
20
21              The Company's cost benefit analysis relies on costly firm transportation backed up by

22              third party storage to provide equivalent reliability and flexibility. While this might

23              have been necessary in 1992 when the study was prepared, the Company now admits

24              that it can obtain sufficient reliability and flexibility without these more expensive

25              options. I discuss this in more detail later in my testimony.

26




     21
          Docket No. 10894, Reply Briefof GSU at 102-103.


     DIRECT TESTIMONY                                  21                                     NALEPA
 1   Q.            WHAT IS THE STATED PURPOSE OF THE SPINDLETOP GAS

 2                 STORAGE FACILITY TODAY?

 3   A.            Ms. Mcllvoy explains that the primary benefits derived from the storage facility are

 4                 increased supply reliability and swing flexibility. In the event of a total curtailment of

 5                 supply, Spindletop is capable of providing 100 percent of the fuel requirements for all

 6                 five units at Sabine Station and either one of the Lewis Creek units for a period of up

 7                 to four days, at a 70 percent capacity factor. The storage facility also provides

 8                 flexibility of gas supply to Sabine Station and Lewis Creek, both on a daily and

 9                 .
                   mstantaneous bas1s.
                                   . 22

10

11   Q.            HOW DO OTHER ENTERGY OPERATING COMPANIES OBTAIN SUPPLY

12                 RELIABILITY AND SWING FLEXIBILITY?

13   A.           According to Ms. Mcllvoy, other operating companies obtain supply reliability and

14                 swing flexibility simply through the companies' monthly, daily, and intra-day natural

15                gas supply contracts. 23 Entergy Gulf States Louisiana ("EGSL") for example has no

16                firm transportation contracts, no firm supply contracts, and no fuel oil back-up at its

                                                    24
17                generating plants in Louisiana.        The only cost incurred by EGSL for reliability and

18                flexibility is the commodity cost of the gas purchased at its generating plants. 25

19




     22
          Direct Testimony of Karen Mcllvoy, p. 32-33.
     23
          Deposition of Karen Mcllvoy, p. 32.
     24
          Id., p. 26-29.
     25
          Id., p. 33.


     DIRECT TESTIMONY                                      22                                      NALEPA
 1   Q.           DO THE OTHER OPERATING COMPANIES EXPERIENCE THE SAME

 2                LEVEL OF SERVICE AS ETI?

 3   A.           Ms. Mcllvoy claims that ETI provides a much higher level of service than does

 4                EGSL, reasoning that Spindletop would protect ETI's operations in the event of an

 5                extreme gas curtailment such as a hurricane or freeze-off, because it would allow ETI

 6                to operate for four days without the need to obtain gas from outside sources. 26 Even

 7                Ms. Mcllvoy admits, however, that EGSL is subject to the same risks for hurricanes

 8                and freeze-offs as is ETI, and that the Entergy System has nonetheless determined

 9                that EGSL does not need firm transportation contracts, firm supply contracts, fuel oil

10                back-up, or gas supply backed up by gas storage at its generating plants. And while

11                EGSL is backed up by other generating units and purchased power in the event of the

12                loss of fuel supply, so is ETI. 27 In short, the options for reliability and flexibility at

13                EGSL also exist at ETI, without incurring the cost of the Spindletop facility for the

14                Louisiana generating plants.

15

16   Q.           YOU MENTIONED              THAT ONE REASON THAT ETI MAINTAINS

17                SPINDLETOP IS FOR PROTECTION AGAINST EXTREME EVENTS SUCH

18                AS HURRICANES. DO YOU HA VE ANY ADDITIONAL COMMENTS ON

19                THIS?

20   A.           Yes. The Company testified that the Spindletop facility was out of service for nearly

21                2 weeks when Hurricane Rita made landfall in 2005. 28 While the facility was


     26/d., p. 44.
     27
          /d., p. 44-46.
     28
          Docket No. 32710, Rebuttal Testimony of KenroyHinkson, p. l 0.


     DIRECT TESTIMONY                                    23                                         NALEPA
 1              prudently evacuated for safety reasons, this event highlights the fact that the facility

 2              was not available for the specific purpose the Company argues makes it valuable.

 3

 4   Q.         PLEASE SUMMARIZE THE FINDINGS RELATED TO THE SPINDLETOP

 5              NATURAL GAS STORAGE FACILITY THAT YOU DEVELOPED EARLIER

 6              IN YOUR TESTIMONY.

 7   A.         The Company could, and has, entered into long term gas supply and transportation

 8              agreements that provide the same reliability and flexibility as the Spindletop facility,

 9              at a lower cost. Therefore, I adjusted storage costs incurred during the reconciliation

10              period to reflect the reasonable cost of providing these services to customers.

11

12   Q.         WHAT WERE THE TEST YEAR COSTS ASSOCIATED WITH THE

13              FACILITY?

14   A.         Table 9 summarizes the test year expenses associated with the Spindletop facility.

15              Total base rate costs are $7,653,293 and total variable non-gas operating costs

16              recovered in the fuel factor are $5,424,895.

17

18   Q.         CAN YOU ESTIMATE THE TOTAL COST OF OPERATING THE

19              SPINDLETOP FACILITY?

20   A.         Yes. The sum oftest year base rate and variable O&M costs is $13,078,188. These

21              costs divided by the sum of the test year withdrawals and adjustments of 8,560,604

22              MMBtu, results in an all-in per unit rate of $1.53 per MMBtu. 29



     29
          ($7,653,293   $5,424,895) I (8, l 06,576 + 454,028)   =   $1.53 per MMBtu.


     DIRECT TESTIMONY                                       24                                    NALEPA
     Q.         PLEASE SUMMARIZE THE ALTERNATIVES TO STORAGE THAT

 2              PROVIDE SUPPLY RELIABILITY AND SWING FLEXIBILITY TO THE

 3              SABINE AND LEWIS CREEK STATIONS.

 4   A.         Effective December 2008, ETI entered into a long-term gas supply and transportation

 5              agreement with Enbridge Pipeline L.P. The agreement will provide increased supply

 6              reliability at Lewis Creek and Sabine because the supply associated with the Enbridge

 7              agreement is from the Barnett Shale and East Texas production areas rather than the

 8              prior south Texas and Louisiana Gulf Coast production areas, which are susceptible

 9              to tropical weather related disruptions. The agreement adds diversity to ETI's supply

10              portfolio and therefore reduces the dependence on the other intrastate pipelines at

11              both plants. 30

12                        In addition, spot gas to meet swing requirements can be delivered through

13              multiple pipeline connections at both plants, 31 and The Company can even take

14              advantage of imbalances under its operational balancing agreement with TETCO

15              pipeline for hourly swing flexibility, depending on operating conditions. 32 Other

16              pipelines provide swing service as well. For instance, Capano Pipeline serving the

17              Lewis Creek plant,
                                                                                            33
18




     30
          Docket No. 37744, Direct Testimony of Devon Jaycox, p. 15-17.
     31
          Schedule I-6.
     32
          Response to Cities RFI 18-14.
     33
          Schedule I-6, Intrastate Gas Transportation Agreement with Copano Pipeline (Highly Sensitive).


     DIRECT TESTIMONY                                      25                                              NALEPA
 1   Q.         CONSIDERING THESE OTHER OPTIONS, DID YOU DO A COST

 2              BENEFIT STUDY OF THE SPINDLETOP FACILITY?

 3   A.         Yes, I did. The results are presented above in Table 10. Based on the operating plans

 4              for EGSL's generating plants, sufficient reliability and swing flexibility can be

 5              obtained through the existing natural gas supply and transportation contracts at

 6              Sabine and Lewis Creek. Compared to the $1.53 per MMBtu cost of operating the

 7              Spindletop facility, transportation on various pipelines connected to Sabine and Lewis

 8              Creek ranged from 2.5¢ to 22¢ per MMBtu. I used as an average transportation rate

 9              the margin between the average cost of gas delivered to the Sabine Station and the

10              Gas Daily Houston Ship Channel Index. This average margin is 18¢ per MMBtu and

11              is a reasonable rate because Spindletop primarily serves the Sabine Station and the

12              daily index best represents the supply flexibility described by Ms. Mcllvoy in her

13              deposition. I then added call options to provide the additional supply reliability that

14              ETI claims is provided by storage. I included call options on 35,000 MMBtu/d for 5

15              days at a cost of $0.15 per option, and purchased options for June through September

16              and January through March. These assumptions are consistent with the Company's

17              experience during the last rate case. 34

18                      Using 18¢ per MMBtu as the replacement cost of providing flexibility and the

19              call options to provide reliability, the cost of the test year Spindletop withdrawals and

20              adjustments of 8,560,604 MMBtu would have been $1,724,659. On a total cost basis,

21              the Spindletop facility costs $13 .1 million per year to operate compared to $1. 7

22              million for the same amount of gas delivered by other existing contracts. ETI could



     34
          Docket No. 37744, Direct Testimony of Devon Jaycox, Exhibit DSJ-2.


     DIRECT TESTIMONY                                    26                                     NALEPA
 1                 save its customers $11.4 million per year by simply relying on its other supply

 2                 options and selling the facility or at least removing it from regulated service
 ,.,
 .J


 4     Q.         WHAT IS YOUR RECOMMENDATION REGARDING THE COST TO

 5                OPERATE AND MAINTAIN THE SPINDLETOP STORAGE FACILITY?

 6     A.         No other Entergy Operating Company owns its own gas storage facility 35 and the

 7                supply reliability and swing flexibility provided by Spindletop can be obtained under

 8                other existing gas supply and transportation contracts at a much lower cost.

 9                Therefore, the costs outlined in Table 9 should be removed from the cost of service

10                and fuel factor. Total base rate costs to be removed are $7,653,293 and the

11                Commission should also exclude as an eligible fuel expense the variable non-gas

12                operating costs of the Spindletop facility. During the test year these costs were

13                $5,424,895. I will discuss the non-gas operating costs that should be excluded from

14                the reconciliation period in the fuel reconciliation portion of my testimony.

15

16                                          C.      COAL INVENTORIES

17     Q.         WHY DOES THE COMP ANY REQUIRE COAL INVENTORIES?

18     A.         Coal is obtained from the Power River Basin ("PRB") in Wyoming and delivered by

19                rail, 36 so coal inventories are maintained at ETI's coal-fired power plants to help




       35
            Response to Cities 18-15.
       36
            Direct Testimony of Ryan Trushenski, p. 6-7.


       DIRECT TESTIMONY                                    27                                        NALEPA
 1              mitigate delivery uncertainties, physical measurement uncertainties, and plant

 2                 .
                equipment f:m·1 ures. ·37

 3

 4   Q.         WHAT ARE THE COMPANY'S TARGET INVENTORY LEVELS?

 5   A.         For Nelson 6, the current inventory policy provides for (1) a base target of 290,000

 6              tons (36 days) of inventory and (2) an average annual inventory target of 340,000

 7              tons (43 days). 38

 8

 9   Q.         WHAT LEVEL OF COAL INVENTORY IS THE COMPANY REQUESTING?

10   A.         ETI is requesting an average test year inventory level of $6,740,528. 39 This reflects its

11              actual inventory level at test year end of approximately -         tons and is equivalent

12              to approximately. days of inventory at full burn. 40

13

14   Q.         DO YOU AGREE WITH THE COMPANY'S REQUESTED LEVEL OF

15              INVENTORY?

16   A.         No. Figure 1 compares the actual and target inventory levels.

17




     37
          Schedule E-2.1.
     38 /d.

     39
          Schedule E-2.3.
     40
          ETI Response to Cities 6-28 (Highly Sensitive).


     DIRECT TESTIMONY                                       28                                   NALEPA
                                             FIGURE 1




                        HIGHLY SENSITIVE MATERIAL REDACTED




 1

 2         The Company's actual inventory levels far exceed its target inventory level. Since the

 3         Company has established that its average target inventory of 43 days at Nelson 6 is

 4         sufficient to meet its reliability requirements, there is no reason to require customers

 5         to pay for more than this level of inventory. In other words, customers should not be

 6         responsible for paying for inventory levels over and above the inventory levels the

 7         Company determined to be reasonable and necessary. Therefore, I recommend that

 8         the 43 day coal inventory level amount be included in rate base, resulting in a revised

 9         inventory level for Nelson 6 of $4,381,988 and reducing the Company's requested

10         inventory level by $2,358,540.

11

12

13




     DIRECT TESTIMONY                          29                                         NALEPA
                             D.      RENEWABLE ENERGY CREDIT RIDER

 2   Q.           PLEASE DESCRIBE RENEW ABLE ENERGY CREDITS.

 3   A.           To encourage the development of renewable energy technologies and to meet the

 4                State's goals for renewable capacity, the Commission has adopted a set of rules

 5                governing the issuance and trading of Renewable Energy Credits ("RECs"). 41 A

 6                "retail entity" must hold RECs equal to its proportionate share of sales based on the

 7                State's renewable energy goals on an annual basis, and a generator will earn RECs

 8                when it generates energy from a renewable energy resource.

 9

10   Q.           HOW ARE REC COSTS CURRENTLY RECOVERED?

11   A.           REC costs are currently recovered through base rates. 42

12

13   Q.           HOW IS THE COMPANY PROPOSING TO TREAT ITS PURCHASE OF

14                RENEWABLE ENERGY CREDITS?

15   A.           The Company is requesting approval of a Renewable Energy Credit Rider ("REC") in

16                this case. It proposes to shift recovery of its renewable energy credit costs from base

17                rates to the REC Rider. The initial amount to be included in the Rider is $633,985,

18                based on test year REC costs. 43 The grossed up amount will be divided by non-

19                transmission level KWh sales and applied to applicable retail rate schedules.

20                Customers taking transmission level service are eligible to opt out of the Rider. 44



     41
           16 TAC §25.173. Goa/for Renewable Energy.
     42
          Direct Testimony of Heather LeBlanc, p. 25.
     43
          ETI Schedule Q-1 (Rev.)
     44
          /bid., p. 26.


     DIRECT TESTIMONY                                   30                                        NALEPA
 1

 2   Q.           HOW WOULD THE REC RIDER BE ADJUSTED AS COSTS CHANGE

 3                OVER TIME?

 4   A.           The Company proposes that the tariff be updated on an annual basis and on or before

 5                May 1, beginning in 2013, a redetermination of purchased power rates would be

 6                made. The revised rate will include: 45

 7                        •   renewable energy credit costs that the Company expects to incur during
 8                            the twelve-month period beginning June l immediately following the
 9                            filing;
10                        •   a true-up adjustment for past over(under)-recovery of Rider REC revenue;
11                            and
12                        •   any corresponding revenue-related expenses associated with the recovery
13                            of the above costs
14

15   Q.           WHY IS THE COMPANY PROPOSING THE RIDER IN THIS CASE?

16   A.           The Company argues that because RECs are mandated by law, the costs are variable,

17                and because certain customers can opt out of the Rider, the REC Rider is the most

18                efficient method to recover the costs. 46

19

20   Q.           DO YOU AGREE WITH THE COMPANY'S PROPOSAL?

21   A.           No. The Commission should not permit the Company to single out REC costs from

22                base rates. It has presented no evidence that suggests the costs should be treated

23                differently than they are now. RECs are not related to fuel so much as they are related

24                to retail sales and plant output. And RECs must be held to meet the renewal energy



     45   !bid.
     46
          /bid., p. 25.


     DIRECT TESTIMONY                                   31                                      NALEPA
 1              rules but the purchase and sale of the RECs are not related to fuel consumption at all.

 2              For example, these transactions have occurred generally on an annual basis, as

 3               summarized in Table 11 for the years since 2006. 47

                                                        TABLE 11
                                                                                        I
                                  Year                    Month           Amount
                                  2006                     March            $323,561
                                  2007                     March            $390,864
                                  2008                     March            $873,064
                                  2009                    January           $367,500
                                                         February           $185,000
                                                           March            $138,616
                                  2010                      June            $378,469
                                  2011                      Mar             $584,000
                        I                                   Apr              $47,803


 4   Q.         WHAT AMOUNT OF REC EXPENSE DO YOU RECOMMEND BE

 5              INCLUDED IN BASE RATES?

 6   A.         I recommend the adjusted test year amount of $633,985.

 7

 8                                   E.       COST OF SERVICE MODEL

 9   Q.         ARE THE CITIES PROPOSING AN OVERALL REVENUE REQUIREMENT

10              IN THIS PROCEEDING?

11   A.         Yes. I am sponsoring a cost of service model based on the Company's model, and

12              have compiled the adjustments to the Company's proposed revenue requirement

13              recommended by each of the Cities' experts. The cost of service model is included as

14              Attachment KJN-1.

15



     47
          Response to Staff RFI 2-8 and State of Texas RF! 4-10.


     DIRECT TESTIMONY                                      32                                 NALEPA
 1   Q.         HOW WAS THE COST OF SERVICE MODEL DEVELOPED?

 2   A.         The cost of service model is a reproduction of the Company's model. It incorporates

 3              all of the components of the Company's model, and generates the same results as the

 4              Company's model prior to any adjustments by the City.

 5

 6   Q.         ARE YOU SPONSORING THE CITIES' ADJUSTMENTS TO THE COST OF

 7              SERVICE MODEL?

 8   A.         No. I have compiled the adjustments to the cost of service model, but I am only

 9              sponsoring the model. The individual experts sponsor their own adjustments. A

10              summary of the adjustments proposed by Cities' experts is included in my

11              workpapers.

12

13   Q.         WHAT IS THE CITIES' PROPOSED REVENUE REQUIREMENT?

14   A.         The Company is proposing a total revenue requirement of $1 ,493.5 million, which is

15              an increase of $111. 8 million over current revenues. 48 The Cities' proposed revenue

16              requirement is $1,367.5 million, which is $126.0 million less than the Company's

17              proposed revenue requirement and approximately $14.2 million less than current

18              revenues.   Although Cities adjustments would support a decrease in current rates,

19              Cities are recommending that the rates set by agreement and approved by the

20              Commission in Docket No. 37744 remain in effect.

21

22



     48
          Schedule Q-1.


     DIRECT TESTIMONY                              33                                       NALEPA
 1                                F.      COST ALLOCATION

 2

 3   Q.    WHAT ISSUE DO YOU ADDRESS IN THIS SECTION OF YOUR

 4         TESTIMONY?


 5   A.    In this section of my testimony I address an alternative class cost allocation issues.

 6         Specifically, I address the Company's proposed production and transmission related

 7         class cost allocation employing the Average and Excess/4 Coincident Peak

 8         ("A&E/4CP") allocation method. I also address the Company's complete failure to

 9         recognize substantial cost changes and uncertainties occurring in the near future.


10   Q.    WHAT IS THE IMPACT, BY CUSTOMER CLASS, OF THE PROPOSED

11         RATE INCREASE UNDER THE COMPANY'S COST ALLOCATION

12         METHOD?


13   A.    The Company's proposed increase by customer class is set forth in Table 12:


14                                               TABLE12
              Customer Class                    Increase                       Percent
          Residential                         $ 82,095,079                     21.64%
          Small General                          $ 428,754                       1.62%
          General                              $ 7,690,498                      4.81%
          Large General                        $ 8,171,696                     16.55%
          LIPS                                $ 11,233,897                     10.77%
          Lighting                             $ 2,203,940                     20.38%

                 Total                       $ 111,823,864                      15.32%
15




     DIRECT TESTIMONY                           34                                         NALEPA
 1         As can be seen from the above table, the residential and lighting customer classes

 2         receive the highest rate increases while the Small General Service, General Service,

 3         and LIPS classes receive below system average rate increases of 1.62%, 4.81 %, and

 4         10. 77%, respectively.


 5   Q.    HA VE THE RESIDENTIAL AND LIGHTING CUSTOMERS PLACED AN

 6         INCREASED BURDEN ON THE SYSTEM DUE TO LOAD OR CUSTOMER

 7         GROWTH?


 8   A.    No. I have examined test year customer quantities, energy and loads by customer

 9         class for each of the last three cases. Residential and lighting customers are not

10         imposing an undue cost burden on the system. Instead, other classes are growing at a

11         faster rate causing system costs to increase.


12   Q.    HOW DOES THE COMPANY PLAN FOR SYSTEM GROWTH TO MEET

13         PRODUCTION AND TRANSMISSION DEMANDS?


14   A.    The system is planned pursuant to the requirements of the System Agreement. Under

15         the System Agreement production and transmission assets are added and costs are

16         incurred based on meeting the EOC's peak demands coincident with the System peak.

17         (See Section 2.16 of the System Agreement) Moreover, the System is planned and

18         costs are incurred to meet all twelve monthly System coincident peaks ("12 CP").

19         Cost responsibility under the System Agreement for production and transmission

20         costs (MSS-1 and MSS-2 tariffs) is assigned to each Entergy Operating Company

21         ("EOC") based on the 12 CP.




     DIRECT TESTIMONY                           35                                         NALEPA
 1   Q.            ARE CHANGES OCCURRING ON THE SYSTEM THAT CAN AFFECT

 2                 SYSTEM AND SPECIFICALLY ETI'S COSTS?


 3   A.            Yes, a number of factors are occurring which will impact costs. First, the Entergy

 4                 Operating Company's ("EOC's") are seeking approval for a change in control and

 5                 joining the Midwest Independent System Operator ("MISO") as the Regional

 6                 Transmission Organization ("RTO"). A change to the current Independent

 7                 Coordinator of Transmission ("ICT") could have implications" ... for the quantity and

 8                 mix of resource requirements ... " 49 Thus, system production plans and costs may be

 9                 impacted and quite possibly substantially impacted by the MISO decision.


10                 Another potential impact on System planning and costs is the fact that Entergy

11                 Arkansas ("EAI") and Entergy Mississippi ("EMI") are leaving the joint system.

12                 These EOC' s - EAI and EMI - have given their respective notice to exit the System

13                 Agreement. The impact of EAI and EMI on the remaining four EOC Systems is not

                                                                                             50
14                 known at this time, but production costs and planning will be impacted.


15   Q.            ARE THERE OTHER CHANGES THAT MAY IMPACT SYSTEM COSTS?


16   A.            Yes, recently Entergy Corp announced its plan to totally divest the EOC' s including

17                 ETI of the transmission system. In other words, the EOC's and ETI would purchase

18                 transmission service from a third party and there would be no transmission

19                 investment to allocate or to plan in the future.




     49
          See 2009 Strategic Resource Plan Refresh at 5.
     50
          Idat4.


     DIRECT TESTIMONY                                      36                                     NALEPA
 1   Q.         GIVEN THE SUBSTANTIAL CHANGES EXPECTED TO IMPACT THE

 2              SYSTEM, HOW SHOULD THE RATE CHANGES AND COST

 3              RESPONSIBILITY BE ALLOCATED AMONG CUSTOMER CLASSES?


 4   A.         At this time, given the changes and uncertainties with MISO, the System Agreement

 5              and the proposed divestiture of the entire transmission system, I propose that any

 6              increase or decrease be spread proportionately across the system classes. Once

 7              Entergy and ETI address the proposed system cost changes - a reasonable class cost

 8              allocation study can be presented.


 9


10                             v.        OVERVIEW OF ETl'S FUEL COSTS

11

12   Q.         WHAT ARE THE COMPANY'S TOTAL FUEL AND PURCHASED POWER

13              EXPENSES DURING THE RECONCILIATION PERIOD?

14   A.         For the period July 1, 2009 through June 30, 2011, ETI generated or purchased

15              44,145,144 MWh at a total cost of $1,697,471,673 or an average cost of $38.45 per

16              MWh. The Company had off-system sales of 7,778,021 MWh with total revenues of

17              $376,671,971 or average revenue of $48.43 per MWh. The net cost during the period

18              was $36.32 per MWh. 51

19




     51
          Direct Testimony of Gregory Zakrzewski, Exhibit GRZ-1.


     DIRECT TESTIMONY                                   37                                    NALEPA
     Q.    WHAT IS THE STANDARD BY WHICH ETI'S FUEL COSTS SHOULD BE

 2         EVALUATED?

 3   A.    PUC Rule §25.236 (d) requires that in a proceeding to reconcile fuel factor revenues

 4         and expenses, an electric utility has the burden of showing that:

 5              (A) its eligible fuel expenses during the reconciliation period were reasonable
 6                  and necessary expenses incurred to provide reliable electric service to retail
 7                  customers;
 8              (B) if its eligible fuel expenses for the reconciliation period included an item or
 9                  class of items supplied by an affiliate of the electric utility, the prices
10                  charged by the supplying affiliate to the electric utility were reasonable and
11                  necessary and no higher than the prices charged by the supplying affiliate
12                  to its other affiliates or divisions or to unaffiliated persons or corporations
13                  for the same item or class of items; and
14              (C) it has properly accounted for the amount of fuel-related revenues collected
15                  pursuant to the fuel factor during the reconciliation period.
16


17                            VI.     FUEL COST ADJUSTMENTS

18

19   Q.    PLEASE DESCRIBE THE FUEL COST ADJUSTMENTS YOU ARE

20         RECOMMENDING.

21   A.    I am recommending several adjustments to fuel costs related to:

22         1. Natural Gas Storage Costs
23         2. Line Loss Factors
24

25                       A.         NATURAL GAS STORAGE COSTS

26   Q.    PLEASE DESCRIBE THE COMPANY'S NATURAL GAS STORAGE

27         FACILITY.

28   A.    The Spindletop storage facility consists of two salt-dome storage caverns, a

29         compression facility used for injecting gas into the caverns, and a pipeline header




     DIRECT TESTIMONY                           38                                        NALEPA
                  system that interconnects the storage caverns with Sabine Station. The Lewis Creek

 2                station is served from Spindletop through interconnections with Kinder Morgan Tejas

                                                                                      52
 3                Gas Pipeline, Kinder Morgan Texas Pipeline, and Copano Pipeline.         In 2004, the

 4                Company purchased the Spindletop gas storage facility from Spindletop Gas

 5                Transmission Company. Beginning in January 2005, the Company contracted with

 6                PB Energy Storage Services ("PB Energy") to operate the facilities. The payments

 7                ETI makes to PB Energy are treated as fuel payments and are included in the fuel

 8                reconciliation.

 9

10   Q.           WHAT IS THE PURPOSE OF THE SPINDLETOP GAS STORAGE

11                FACILITY?

12   A.           As detailed earlier in my testimony, Ms. Mcllvoy explains that the primary benefits

13                derived from the storage facility are increased supply reliability and swing

14                fl ex1"b"l"
                          11ty. 53

15

16   Q.           HOW HAS THE SPINDLETOP GAS STORAGE FACILITY BEEN USED?

17   A.           Figure 1 shows by month the sum of daily injections and withdrawals during the

                                           54
18                reconciliation period.

19




     52
          Direct Testimony of Karen Mcllvoy, p. 31.
     53
          /d., p. 32-33.
     54
          /d., Exhibit KDM-12.


     DIRECT TESTIMONY                                 39                                      NALEPA
 1                                                     FIGURE 2

                                     Spindletop Gas Inventory Activity
                      1,500,000

                      1,000,000

                        500,000




                                     iii Injections   D Withdrawals   D Adjustments
 2

 3

 4   Q.         WHAT WERE THE ELIGIBLE FUEL COSTS ASSOCIATED WITH THE

 5              FACILITY?
                                                                                                       55
 6   A.         Table 13 summarizes the eligible fuel costs associated with the Spindletop facility.


                                                   TABLE 13
                    Payments to         Costs Allocated to  Costs Allocated to        Eligible Fuel
                  Storage Operator          Injections        Withdrawals                 Costs
                    $10,002, 745           $(144,752)           $403,670               $10,261,663

 7

 8   Q.         ARE THE SPINDLETOP STORAGE COSTS REASONABLE?

 9   A.         No. As I discussed earlier in my testimony, the costs are not reasonable and the

I0              facility should be removed from rates.

11




     55
          id., Exhibit KDM-13.


     DrRECT TESTIMONY                                     40                                   NALEPA
 l   Q.          HA VE YOU MADE AN ADJUSTMENT TO STORAGE COSTS FOR THE

 2               RECONCILIATION PERIOD?

 3   A.          Yes. The Company can and has entered into long term gas supply and transportation

 4               agreements that provide the same reliability and flexibility as the Spindletop facility,

 5               at a lower cost. I have adjusted the storage costs to reflect this alternative.

 6

 7   Q.          PLEASE SUMMARIZE THE ALTERNATIVES TO STORAGE THAT

 8              PROVIDE SUPPLY RELIABILITY AND SWING FLEXIBILITY TO THE

 9               SABINE AND LEWIS CREEK STATIONS.

10   A.          Effective December 2008, ETI entered into a long-term gas supply and transportation

11              agreement with Enbridge Pipeline L.P. The agreement will provide increased supply

12              reliability at Lewis Creek and Sabine because the supply associated with the Enbridge

13              agreement is from the Barnett Shale and East Texas production areas rather than the

14              prior south Texas and Louisiana Gulf Coast production areas, which are susceptible

15              to tropical weather related disruptions. The agreement adds diversity to ETI's supply

16              portfolio and therefore reduces the dependence on the other intrastate pipelines at

17              both plants. 56

18                        In addition, spot gas to meet swing requirements can be delivered through

19              multiple pipeline connections at both plants, 57 and the Company can even take

20              advantage of imbalances under its operational balancing agreement with TETCO

21              pipeline for hourly swing flexibility, depending on operating conditions. 58 Other


     56
          Docket No. 37744, Direct Testimony of Devon Jaycox, p. 15-17.
     57
          Schedule I-6.
     58
          Response to Cities RFI 18-14.


     DIRECT TESTIMONY                                    41                                        NALEPA
 1              pipelines provide swing service as well. For instance, Copano Pipeline serving the

 2              Lewis Creek plant,
                                                                                             59
 3




 4   Q.         CONSIDERING THESE OTHER OPTIONS, DID YOU DO CALCULATE AN

 5              ADJUSTMENT TO STORAGE COSTS?

 6   A.         Yes. Based on the operating plans for EGSL' s generating plants, sufficient reliability

 7              and swing flexibility can be obtained through the existing natural gas supply and

 8              transportation contracts at Sabine and Lewis Creek. Transportation rates on various

 9              pipelines connected to Sabine and Lewis Creek ranged from 2.5¢ to 22¢ per MMBtu.

10              I used as an average transportation rate the margin between the average cost of gas

11              delivered to the Sabine Station and the Gas Daily Houston Ship Channel Index. This

12              average margin is 18¢ per MMBtu and is a reasonable rate because Spindletop

13              primarily serves the Sabine Station and the daily index best represents the supply

14              flexibility described by Ms. Mcilvoy in her deposition. I then added call options to

15              provide the additional supply reliability that ETI claims is provided by storage. I

16              included call options on 35,000 MMBtu/d for 5 days at a cost of $0.15 per option, and

17              purchased options for June through September and January through March. These

18              assumptions are consistent with the Company's experience during the last rate case. 60

19




     59
          Schedule I-6, Intrastate Gas Transportation Agreement with Copano Pipeline (Highly Sensitive).
     60
          Docket No. 37744, Direct Testimony of Devon Jaycox, Exhibit DSJ-2.


     DIRECT TESTIMONY                                      42                                              NALEPA
 1     Q.         WHAT IS YOUR RECOMMENDATION REGARDING THE COST TO

 2                OPERATE AND MAINTAIN THE SPINDLETOP STORAGE FACILITY?
 ,.,
 .)    A.         The average operating cost of the Spindletop facility during the reconciliation period

 4                was $0.56 per MMBtu. 61         I restated the average operating cost at the Spindletop

 5                facility to $0.18 per MMBtu plus the call options to provide reliability for the period

 6                and applied the resulting average $0.20 per MMBtu rate to the period withdrawals

 7                and adjustments of 18,331,863 MMBtu. This reduces storage costs to $3,666,373, or

 8                $6,595,290 less than the period amount. I addressed the base rate portion of

 9                Spindletop-related costs earlier in my testimony.

10

11                                           B.      LOSS FACTORS

12

13     Q.         WHAT ISSUE DO YOU ADDRESS IN THIS SECTION OF YOUR

14                TESTIMONY?

15     A.         In this section of my testimony, I recommend that the Commission approve ETI's

16                updated calculation of line loss factors and associated line loss multipliers. The line

17                loss study was performed by ETI for the annual period ending December 31, 2010, in

18                order to fairly allocate base rate demand and energy costs in this case to the wholesale

19                class and the respective retail customer classes based upon the delivery voltage level

20                of each customer. Loss factors are the actual average line losses experienced at each

21                voltage level of the ETI transmission and distribution system. Line loss multipliers

22                are the corresponding factors for each customer class, wholesale and retail, based



       61
            $10,261,663 (Exhibit KDM-13) I 18,331,863 (Exhibit KDM-12)   =   $0.56 per MMBtu.


       DIRECT TESTIMONY                                  43                                      NALEPA
                upon the make-up of the various voltage level customers within that class.            The

 2              purpose of line loss factors and line loss multipliers is to ensure that customers, who

 3               are billed for energy at the meter, are responsible for their fair share of costs incurred

 4               at the plant.

 5

 6   Q.         IS THERE A PROBLEM WITH CONTINUING TO USE THE LINE LOSS

 7              FACTORS AND ASSOCIATED LINE LOSS MULTIPLIERS REFLECTED IN

 8              ETI'S FUEL FACTOR?

 9   A.         Yes. ETI' s proposed tariff Schedule FF Fixed Fuel Factor62 includes loss multipliers

10              by voltage level which were calculated in a study based on the 12 months ending

11              December 31, 1997, and approved in Docket No. 19834. The loss factors by voltage

12              level used to calculate the fuel factor and any fuel factor over/(under) recovery, are

13              over 14 years old and do not represent the current cost of providing service to the

14              wholesale customers or to the various retail customer classes. ETI's own analysis

15              demonstrates that adjusting the allocation of fuel costs over the reconciliation period

16              to reflect the actual line losses for each voltage level for the reconciliation period

17              results in retail customers subsidizing wholesale customers by approximately $3.98

18              million.

19




     62
          Schedule Q-8.8, p. 26.1.


     DIRECT TESTIMONY                                 44                                          NALEPA
 1   Q.          ARE      THERE        MORE     RECENT       LOSS     FACTORS        AVAILABLE          TO

 2               CALCULATE THE FIXED FUEL FACTOR?

 3   A.          Yes there are.       ETI performed a line loss study for the twelve months ending

 4               December 31, 2010, which falls squarely within the current reconciliation period.

 5               Schedule 0-6.3 of the Company's rate filing package provides the results of the line

 6               loss study and ETI's amended response to Cities' RFI 6-1 provides the corresponding

 7               line loss multipliers by customer class. ETI uses these loss factors to calculate the

 8               demand and energy related allocation factors in its Schedule P-9 cost of service

 9              analysis, but did not apply these current loss factors to its fuel factor reconciliation. In

10               ETI's response to Cities' RFI 16-9, ETI applies these line loss factors to the fuel costs

11               over the reconciliation period.

12

13   Q.         HAVE YOU CALCULATED THE IMPACT ON THE RETAIL CUSTOMER

14              CLASS ALLOCATION OF FUEL COSTS USING THE CURRENT LOSS

15              FACTORS?

16   A.         Yes I have.       In response to a request for information, 63 the Company provided a

17              revised Schedule I-22A for the reconciliation period of July 2009 through June 2011

18              which was updated to reflect the actual loss factors calculated by the Company in

19              Docket No. 39896 for the annual period in the middle of the two-year reconciliation

20              period. In addition the Company provided kWh sales at the meter for each customer

21              class for the reconciliation period. Using the data provided in this RFI response, I




     63
          ET!' s Response to Cities RFI 16-9.


     DIRECT TESTIMONY                                 45                                          NALEPA
 1         have calculated the actual fuel costs incurred at the plant by wholesale customers and

 2         retail customer classes by voltage level.

 3

 4   Q.    PLEASE DESCRIBE YOUR ANALYSIS.

 5   A.    I first allocated the Company's proposed Fixed Fuel Factor allocable fuel cost

 6         provided in the rate filing package Schedule I-22a using metered kWh adjusted for

 7         losses using the 1997 loss factors. This allocation is provided on pages 2 through 6 of

 8         23 in my Fuel Cost Recovery workpapers. I then allocated the fuel cost provided in

 9         the updated Schedule I-22a included in the response to requests for information using

10         metered kWh adjusted for losses based on the Company's current actual loss factors.

11         This allocation is provided on pages 7 through 11 of 23 in my Fuel Cost Recovery

12         workpapers and reflects the actual fuel costs at plant incurred by wholesale and retail

13         customers at each voltage level. Pages 12 through 23 of these workpapers detail the

14         loss adjustment to metered kWh using the 1997 and current loss factors.

15

16   Q.    PLEASE DESCRIBE THE RESULTS OF YOUR ANALYSIS.

17   A.    Table 14 compares a fuel cost allocation using line losses calculated in 1997 with the

18         recommended fuel cost allocation using the Company's actual current loss factors

19         provided in Docket No. 39896.

20




     DIRECT TESTIMONY                           46                                       NALEPA
 1

 2

 3                                             TABLE14
                                                                              Cities
                Line
                                 Customer             ETI Allocated         Allocated
          No.                         Class            Fuel Costs          Fuei Costs        Chan e
                                       (a)                 (b)                 (c)            (d)
                       RS Secondary                     466, 940, 745      464,097,898
           2           SGS - SA Secondary                        9,079               8,858
           3           SGS Secondary                     25,354,289         25, 199,082
           4           GS - SA Secondary                    326,370            324,415
           5           GS Secondary                     243,253, 190       241,761,967
           6           GS - SA Primary                      312,020            310,920
           7           GS Primary                        10,904,338         10,867,331
           8           GS 69/138 KV                       5,087, 170          5, 104,073
           9           GS 230 KV                            413,814            415,688
           10          LGS Secondary                     76,900,410         76,427,635
           11          LGS Primary                       31,339,382         31,232,487
           12          LGS 69/138 KV                      4,095,205          4, 108,800
           13          LIPS-CS Primary                    8,771, 136          8,740,784
           14          LPS 69/138 KV                                  0                 0             0
           15          LPS 230 KV                                     0                 0             0
           16          LIPS 69/138 KV                   266,481,094        267,370,925         889,831
           17          LIPS 230 KV                       64,476, 161        64,748,818         272,656
           18          HLFS 69/138 KV                                 0                 0             0
           19          S&OL Secondary                     5,950,713          5,914, 165
          20           Total Retail                   1,210,615,116       1,206,633,845
 4

 5   Q.    WHAT IS YOUR RECOMMENDATION REGARDING THE ALLOCATION

 6         OF FUEL COSTS?

 7   A.   I recommend that the Commission approve the Company's line loss study and

 8         associated line loss factors and multipliers for use in future allocations of fuel costs,

 9         including the proposed future surcharge or refund for fuel factor over (under)

10         recovery. I also recommend that the Commission approve the line loss multipliers

11         calculated by ETI for use in future revisions of the fixed fuel factor tariff Schedule



     DIRECT TESTIMONY                            47                                             NALEPA
1         FF. A comparison of the current fuel factor loss multipliers and those based on the

2         current line loss study performed in Docket No. 39896 are provided in Table 15:

3                                                   TABLEI5
                  Delivery Voltage            1997 Loss Multiplier              2011 Loss Multiplier
                  Secondary                        1.034603                          1.021709
                  Primary                          1.004911                          0.995128
                  68kV/138kV                       0.962921                          0.960014
                  230kV                            0.945741                          0.943839
                  The updated 2011 Loss Multipliers were calculated by the Company and provided in the amended
                  response to RFI Cities 6-1
4
5   Q.    DOES THIS CONCLUDE YOUR TESTIMONY?

6   A.    Yes, it does.




    DIRECT TESTIMONY                                      48                                                     NALEPA
        APPENDIX A

STATEMENT OF QUALIFICATIONS
Blank Page
                                            KARLJ. NALEPA

Mr. Nalepa is an energy economist with more than 25 years of private and public sector experience in the
electric and natural gas industries. He has extensive experience analyzing utility rate filings and resource
plans with particular focus on fuel and power supply requirements, quality of fuel supply management, and
reasonableness of energy costs. Mr. Nalepa developed peak demand and energy forecasts for municipal and
electric cooperative utilities and has forecast the price of natural gas in ratemaking and resource plan
evaluations. He led a management and performance review of the Texas Public Utility Commission, and has
conducted performance reviews and valuation studies of a number of municipal utility systems. Mr. Nalepa
previously directed the Railroad Commission of Texas' Regulatory Analysis & Policy Section, with
responsibility for preparing timely natural gas industry analysis, managing ratemaking proceedings,
mediating informal complaints, and overseeing consumer complaint resolution. He has prepared and
defended expert testimony in both administrative and civil proceedings, and has served as a technical
examiner in natural gas rate proceedings.

EDUCATION
1998            Certificate of Mediation
                       Dispute Resolution Center, Austin

1989            NARUC Regulatory Studies Program
                    Michigan State University

1988            M .S. - Petroleum Engineering
                        University of Houston

1980            B.S. - Mineral Economics
                       Pennsylvania State University

PROFESSIONAL HISTORY
2003 -          ReSolved Energy Consulting, LLC
                (Formerly R.J. Covington Consulting, LLC)
                     President and Managing Director

1997 - 2003     Railroad Commission of Texas
                      Asst. Director, Regulatory Analysis & Policy

1995 - 1997     Karl J. Nalepa Consulting
                       Principal

1992 - 1995     Resource Management International, Inc.
                      Supervising Consultant

1988     1992   Public Utility Commission of Texas
                       Fuels Analyst

1980 - 1988     Transco Exploration Company
                      Reservoir and Evaluation Engineer




                                                       1
AREAS OF EXPERTISE

Regulatory Analysis

Electric Power: Analyzed electric utility rate, certification, and resource forecast filings. Assessed the
quality of fuel supply management, and reasonableness of costs recovered from ratepayers. Projected the
cost of fuel and purchased power. Estimated the impact of environmental costs on utility resource selection.
Participated in regulatory rulemaking activities. Provided expert staff testimony in a number of proceedings
before the Texas Public Utility Commission.

As consultant, represent interests of municipal clients intervening in large utility rate proceedings through
analysis of filings and presentation of testimony before the Public Utility Commission. Also assist municipal
utilities in preparing and defending requests to change rates and other regulatory matters before the Public
Utility Commission.

Natural Gas: Directed the economic regulation of gas utilities in Texas for the Railroad Commission of
Texas. Responsible for monitoring, analyzing and reporting on conditions and events in the natural gas
industry. Managed Commission staff representing the public interest in contested rate proceedings before
the Railroad Commission, and acted as technical examiner on behalf of the Commission. Mediated informal
disputes between industry participants and directed handling of customer billing and service complaints.
Oversaw utility compliance filings and staff rulemaking initiatives. Served as a policy advisor to the
Commissioners.

As consultant, represent interests of municipal clients intervening in large utility rate proceedings through
analysis of filings and presentation of testimony before the cities and Railroad Commission. Also assist
small utilities in preparing and defending requests to change rates and other regulatory matters before the
Railroad Commission.

Litigation Support

Retained to support litigation in natural gas contract disputes. Analyzed the results of contract negotiations
and competitiveness of gas supply proposals considering gas market conditions contemporaneous with the
period reviewed. Supported litigation related to alleged price discrimination related to natural gas sales for
regulated customers. Provided analysis of regulatory and accounting issues related to ownership of certain
natural gas distribution assets in support of litigation against a natural gas utility. Supported independent
power supplier in binding arbitration regarding proper interpretation of a natural gas transportation
contract. Provided expert witness testimony in administrative and civil court proceedings.




                                                       2
Utility System Assessment

Led a management and performance review of the Public Utility Commission. Conducted performance
reviews and valuation studies of municipal utility systems. Assessed ability to compete in the marketplace,
and recommended specific actions to improve the competitive position of the utilities. Provided
comprehensive support in the potential sale of a municipal gas system, including preparation of a valuation
study and all activities leading to negotiation of contract for sale and franchise agreements.

Energy Supply Analysis

Reviewed system requirements and prepared requests for proposals (RFPs) to obtain natural gas and power
supplies for both utility and non-utility clients. Evaluated submittals under alternative demand and market
conditions, and recommended cost-effective supply proposals. Assessed supply strategies to determine
optimum mix of available resources.

Econometric Forecasting

Prepared econometric forecasts of peak demand and energy for municipal and electric cooperative utilities in
support of system planning activities. Developed forecasts at the rate class and substation levels. Projected
price of natural gas by individual supplier for Texas electric and natural gas utilities to support review of
utility resource plans.


Reservoir Engineering

Managed certain reserves for a petroleum exploration and production company in Texas. Responsible for
field surveillance of producing oil and natural gas properties, including reserve estimation, production
forecasting, regulatory reporting, and performance optimization. Performed evaluations of oil and natural gas
exploration prospects in Texas and Louisiana.


PROFESSIONAL MEMBERSHIPS

Society of Petroleum Engineers
International Association for Energy Economics




                                                      3
SELECT PUBLICATIONS, PRESENTATIONS, AND TESTIMONY

"Natural Gas Regulatory Policy in Texas," Hungarian Oil and Gas Policy Business Colloquium, U.S. Trade and
     Development Agency, Houston, May 2003

"Railroad Commission Update," Texas Society of Certified Public Accountants, Austin, April 2003

"Gas Utility Update," Railroad Commission Regulatory Expo and Open House, October 2002

"Deregulation: A Work in Progress," Interview by Karen Stidger, Gas Utility Manager, October 2002

"Regulatory Overview: An Industry Perspective," Southern Gas Association's Ratemaking Process Seminar,
     Houston, February 2001

"Natural Gas Prices Could Get Squeezed," with Commissioner Charles R. Matthews, Natural Gas, December
     2000

"Railroad Commission Update," Texas Society of Certified Public Accountants, Austin, April 2000

"A New Approach to Electronic Tariff Access," Association of Texas Intrastate Natural Gas Pipeline Annual
     Meeting, Houston, January 1999

"A Texas Natural Gas Model," United States Association for Energy Economics North American Conference,
     Albuquerque, 1998

"Texas Railroad Commission Aiding Gas Industry by Updated Systems, Regulations," Natural Gas, July 1998

"Current Trends in Texas Natural Gas Regulation," Natural Gas Producers Association, Midland, 1998

·'An Overview of the American Petroleum Industry," Institute ofinternational Education Training Program,
      Austin, 1993

Direct testimony in PUC Docket No. 10400 summarized in Environmental Externality, Energy Research Group
      for the Edison Electric Institute, 1992

"God's Fuel - Natural Gas Exploration, Production, Transportation and Regulation," with Danny Bivens, Public
     Utility Commission of Texas Staff Seminar, 1992

"A Summary of Utilities' Positions Regarding the Clean Air Act Amendments of 1990," Industrial Energy
     Technology Conference, Houston, 1992

"The Clean Air Act Amendments of 1990," Public Utility Commission of Texas Staff Seminar, 1992

'The Industrial End-Use Model," Chapter Three, End Use Modeling Project: Interim Report, Public Utility
     Commission of Texas, 1989




                                                      4
        APPENDIXB

PREVIOUSLY FILED TESTIMONY




            5
                                                            KARL J. NALEPA
                                                           TESTIMONY FILED


DKTNO. DATE          REPRESENTING                UTILITY                      PHASE                                       ISSUES

Louisiana Public Service Commission
U-31971   Novll      PSC Staff                   Entergy Louisiana, LLC/      Resource Certification      Prudence I Cost Recovery
                                                 Entergy Gulf States Louisiana
Public Utility Commission of Texas
39366     Jul 11     Cities                      Entergy Texas, Inc.          Energy Efficiency    Cost of Service/Rate Design
                                                                              Cost Recovery Factor
38480     Nov 10     Cities                      Texas-New Mexico Power       Cost of Service           Cost of Service/Rate Design
38815     Sep 10     Denton Municipal Electric   Denton Municipal Electric    Interim TCOS             Wholesale Transmission Rate
37744     Jun 10     Cities                      Entergy Texas, Inc.          Cost of Service/                     Cost of Service/
                                                                              Fuel Reconciliation       Nat Gas/ Purch Power/ Gen
37580     Dec 09     Cities                      Entergy Texas, Inc.          Fuel Refund                 Fuel Refund Methodology
36956     Jul 09     Cities                      Entergy Texas, Inc.          EEC RF                          EECRF Methodology
36392     Nov08      TMPA                        TMPA                         Interim TCOS             Wholesale Transmission Rate
35717     Nov08      Cities Steering Committee   Oncor                        Cost of Service           Cost of Service/Rate Design
34800     Apr 08     Cities                      Entergy Gulf States          Fuel Reconciliation         Natural Gas/Coal/Nuclear
16705     May97      North Star Steel            Entergy Texas                Fuel Reconciliation             Natural Gas/Fuel Oil/




                                                                       6
DKTNO. DATE          REPRESENTING                UTILITY                     PHASE                                   ISSUES
Public Utility Commission of Texas (continued}
10694     Jan 92     PUC Staff                   Midwest Electric Coop       Revenue Requirements               Depreciation/
                                                                                                            Quality of Service
10473     Sep 91     PUC Staff                   HL&P                        Notice of Intent            Environmental Costs
10400     Aug 91     PUC Staff                   TU Electric                 Notice oflntent             Environmental Costs
10092     Mar91      PUC Staff                   HL&P                        Fuel Reconciliation         Natural Gas/Fuel Oil

10035     Jun 91     PUC Staff                   West Texas Utilities        Fuel Reconciliation                 Natural Gas
                                                                             Fuel Factor            Natural Gas/Fuel Oil/Coal
9850      Feb 91     PUC Staff                   HL&P                        Revenue Req.           Natural Gas/Fuel Oil/ETSI
                                                                             Fuel Factor             Natural Gas/Coal/Lignite
9561      Aug90      PUC Staff                   Central Power & Light       Fuel Reconciliation                 Natural Gas
                                                                             Revenue Requirements        Natural Gas/Fuel Oil
                                                                             Fuel Factor                         Natural Gas
9427      Jul 90     PUC Staff                   LCRA                        Fuel Factor                          Natural Gas
9165      Feb 90     PUC Staff                   El Paso Electric            Revenue Requirements        Natural Gas/Fuel Oil
                                                                             Fuel Factor                         Natural Gas
8900      Jan 90     PUC Staff                   SWEPCO                      Fuel Reconciliation                  Natural Gas
                                                                             Fuel Factor                          Natural Gas
8702       ser 89    PUC Staff                   Gulf States Utilities       Fuel Reconciliation         Natural Gas/Fuel Oil
           Ju 89                                                             Revenue Requirements        Natural Gas/Fuel Oil
                                                                             Fuel Factor                 Natural Gas/Fuel Oil
8646       May89     PUC Staff                   Central Power & Light       Fuel Reconciliation                 Natural Gas
           Jun 89                                                            Revenue Requirements        Natural Gas/Fuel Oil
                                                                             Fuel Factor                         Natural Gas
8588       Aug 89    PUC Staff                   El Paso Electric            Fuel Reconciliation                  Natural Gas


                                                                         7
DKTNO. DATE         REPRESENTING                UTILITY                    PHASE                                     ISSUES
Railroad Commission of Texas
10106     Oct 11    Gulf Coast Coalition        CenterPoint Energy Entex   Cost of Service       Cost of Service/Rate Design
10083     Aug 11    City of Magnolia, Texas     Hughes Natural Gas         Cost of Service       Cost of Service/Rate Design
10038     Feb 11    Cities Steering Committee   CenterPoint Energy Entex   Cost of Service       Cost of Service/Rate Design
10021     Oct 10    AgriTex Gas, Inc.           AgriTex Gas, Inc.          Cost of Service       Cost of Service/Rate Design
10000     Dec 10    Cities Steering Committee   Atmos Pipeline Texas       Cost of Service       Cost of Service/Rate Design
9902      Oct 09    Gulf Coast Coalition        CenterPoint Energy Entex   Cost of Service Cost of Service/Rate Design/Riders
9810      Jul 08    Bluebonnet Natural Gas      Bluebonnet Natural Gas     Cost of Service       Cost of Service/Rate Design
9797      Apr 08    Universal Natural Gas       Universal Natural Gas      Cost of Service       Cost of Service/Rate Design
9732      Jul 08    Cities Steering Committee   Atmos Energy Corp.         Gas Cost Review                 Natural Gas Costs
9670      Oct 06    Cities Steering Committee   Atmos Energy Corp.         Cost of Service             Affiliate Transactions/
                                                                                                       O&M Expenses/GRIP
9667      Nov06     Oneok Westex Transmission Oneok Westex Transmission Abandonment                            Abandonment
9598      Sep 05    Cities Steering Committee   Atmos Energy Corp.         GRIP Appeal                     GRIP Calculation
9530      Apr 05    Cities Steering Committee   Atmos Energy Corp.         Gas Cost Review                 Natural Gas Costs
9400      Dec 03    Cities Steering Committee   TXU Gas Company            Cost of Service           Affiliate Transactions/
                                                                                                O&M Expenses/Capital Costs




                                                                     8
                                                                                                                                                     Attachment KJN 1
                                                                                                                                                           Page 1of3
         Entergy Texas, Inc.
         Docket No. 39896
         Cities Schedule P
         For the Test Year Ended June 30, 2011


                                                                              ALLOCATION   TOTAL COMPANY
Ln No.                                           DESCRIPTION                                                    TOTAL RETAIL        WHOLESALE
                                                                                FACTOR       ADJUSTED


         SUMMARY OF RES UL TS


         RATE BASE                                                                            1,558,489,613      1,538,729,862        19,759,751
         REVENUES
    2      RATE SCHEDULE REVENUE                                                               648.019,550         634, 114,242       13,905,308
    3      OTHER SALES FOR RESALE                                                               58,675,159          55,518,905         3,156,254
    4     TOTAL SALES REVENUES (L2 + L3)                                                       706,694, 709        689,633, 147       17,061,562
    5     OTHER OPERATING REVENUES                                                              48, 171,991         47,772,887          399, 105
    6     PROVISION FOR RATE REFUND                                                                       0                  0                 0
    7 TOTAL REVENUES (L4 +LS+ L6)                                                              754,866, 700        737,406,034        17,460,666
    8 TOTAL OPERATING EXPENSES                                                                 460,474,258         449,744,074        10,730,184
    9 TOTAL OPERATING INCOME (L7 - LS)                                                         294,392,442         287,661,960         6,730,482
   10 EARNED RATE OF RETURN ON RATE BASE (L9 I L 1)                                                 18.89%               18.69%           34.06%


      REVENUE REQUIREMENT DETERMINATION
   11 REQUIRED RATE OF RETURN                                                                         8.12%              8.12%             8.12%
   12 REQUIRED OPERATING INCOME (L 1*L11)                                                      126,536,524         124,932, 195        1,604,329


         REVENUE CONVERSION FACTORS
   13     INCOME TAX REVENUE CONVERSION FACTOR                                                       53.85%             53.85%            53.85%
   14     REVENUE RELATED TAX REVENUE CONVERSION FACTOR                                               1.03%               1.03%            1.03%
   15     BAD DEBT REVENUE CONVERSION FACTOR                                                          0.27%               0.27%            0.00%

         REVENUE DEFICIENCY
   16     OPERATING INCOME DEFICIENCY (L 12 - L9)                                              (167,855,918)      (162,729,765)       (5,126,153)
   17     INCREMENTAL INCOME TAX (L 16*L13)                                                     (90,383,956)       (87,623,719)       (2,760,236)
   18     INCREMENTAL REVENUE RELATED TAX (L 16+L17+L19) * L 14                                  (2,662,910)        (2,581,781)          (81,129)
   19     INCREMENTAL BAD DEBT EXPENSE (L 16+L17+L18) * L 15                                       (616,247)           (616,247)                0

   20 TOTAL REVENUE DEFICIENCYl(EXCESS) EXCL PUR. PWR. (SUM OF L 16 - L 19)                    (261,519,031)      (253,551,512)       (7,967,519)
   21 PLUS PPR RIDER                                                                            (35,870,747)       (33,941, 188)      (1,929,559)
   22 PLUS IS RIDER                                                               79
   23 PLUS REC RIDER                                                              79
         PLUS MUNICIPAL FRANCHISE FEES
   24 TOTAL REVENUE DEFICIENCY/(EXCESS)                                                        (297,389,778)      (287,492,700)       (9,897.078)
   25 % INCREASEl(DECREASE) (L20 I L2)                                                              -45.89%            -45.34%           -71.17%


   26 RATE SCHEDULE REVENUE REQUIREMENT (L2 + L20)                                             350,629,772         346,621,542         4,008,229


   27 ETl'S REQUESTED REVENUE REQUIREMENT                                                       479,928,299        472,621,802         7.306.497
   28 ETl'S REQUESTED REVENUE DEFICIENCY INCL RIDERS (LINE 24)                                  118, 142,929       111,823,864         6.319,065
   29 CITIES ADJUSTMENT                                                                        (129,298,527)      (126,000,260)        (3,298,268)
   30 REVENUE DEFICIENCYl(EXCESS)                                                               (11,155,598)        (14, 176,396)      3,020,797
   31 CITIES ADJUSTMENT EXCLUDING PPR IS & REC RIDERS                                           (93,427, 780)       (92,059,072)       (1,368.708)
                                                                                                                                   Attachment KJN 1
                                                                                                                                         Page 2 of 3
        Entergy Texas, Inc.
        Docket No. 39896
        Cities Schedule P
        For the Test Year Ended June 30, 2011



I I
Ln No
                                                DESCRIPTION
                                                              ALLOCATION
                                                                FACTOR
                                                                           TOTAL COMPANY
                                                                             ADJUSTED
                                                                                               TOTAL RETAIL        WHOLESALE




        RATE BASE SUMMARY


    1      PLANT IN SERVICE                                                   3, 198,793,204    3, 139,991,077       58,802,127
    2     ACCUMULATED DEPRECIATION I AMORTIZATION                            (1,212,712,279)    (1, 178,895,472)    (33,816,807)
    3    NET PLANT                                                            1,986,080,925     1,961,095,605        24,985,320
    4    WORKING CASH                                                           (21,237,882)      (20,974,670)         (263,212)
    5    FUEL INVENTORY                                                          9,073.881           8,719,426         354,455
    6    MATERIALS AND SUPPLIES EXCLUDING ALLOWANCES                            29,252,574         28,711,438          541.136
    7    PREPAYMENTS                                                             7,218,037          7,186,858           31,179
    8    PROPERTY INSURANCE RESERVE                                             34,051,597         34,051,597                 0
    9    INJURIES & DAMAGES RESERVES                                             (5,569,243)        (5,404, 120)       (165,122)
   10    COAL CAR MAINTENANCE RESERVE                                             1,400,350          1,345,648           54,702
   11    UNFUNDED PENSION                                                        (9,835,109)        (9,543,509)        (291,601)
   12    ALLOWANCES                                                                 68,914              67,647            1,267
   13    COMMERCIAL LITIGATION                                                            0                   0               0
   14    ENVIRONMENTAL RESERVES                                                  (1,062,190)        (1,044,215)         (17,974)
   15    CUSTOMER DEPOSITS                                                      (35,872,476)       (35,872,476)               0
   16    ACCUMULATED DEFERRED INCOME TAXES                                     (441,391,997)      (435,921,599)      (5,470,398)
   17    ACCUMULATED DEFERRED ITC                                                         0                   0               0
   18    RATE CASE EXPENSES                                                       6,175,000          6,175,000                0
   19 REGULATORY ASSETS AND LIABILITIES                                             137,232            137,232                0
   20 RATE BASE                                                               1,558,489,613      1,538,729,862       19,759.751
                                                                               (182,606,822)
                                                                                                                                   Attachment KJN 1
                                                                                                                                         Page 3 of 3
         Entergy Texas, Inc.
         Docket No. 39896
         Cities Schedule P
         For the Test Year Ended June 30, 2011


                                                               ALLOCATION   TOTAL COMPANY
Ln No.                                           DESCRIPTION                                    TOTAL RETAIL       WHOLESALE
                                                                 FACTOR       ADJUSTED


      REVENUES
    1  SALES REVENUES                                                           706,694,709        689,633, 147      17,061,562
    2 OTHER OPERATING REVENUES                                                   48,171,991         47,772,887         399.105
    3 PROVISION FOR RATE REFUND                                                            0                 0               0
    4 TOTAL REVENUES                                                            754,866,700        737,406,034       17,460,666

         OPERATING EXPENSES
          0 & M EXPENSE
    5      PRODUCTION EXPENSES                                                   47,575,533         45,344,134        2,231,399
    6      TRANSMISSION EXPENSES                                                 22,891,692         22,891,692               0
    7      REGIONAL MARKET EXPENSES                                               1,009,426          1,008,442             984
    8      DISTRIBUTION EXPENSES                                                 30,680,337         30,398,544         281,793
    9      CUSTOMER ACCOUNTING EXPENSES                                          17.839,743         17,088,390         751,353
   10      CUSTOMER SERVICES EXPENSES                                             4,340,078          4,340,078                0
   11      SALES EXPENSES                                                         1,089,611          1,070,128           19,483
   12      ADMINISTRATIVE & GENERAL EXPENSES                                     63,160,315         61,282,501        1,877,815
   13     OPERATION & MAINTENANCE EXPENSE                                       '188,586, 734      183,423,907        5,162,827
   14     GAINS FROM DISP OF ALLOWANCES                                                    0                 0                0
   15     REGULATORY DEBITS AND CREDITS                                           5,245,925          4,963,736         282, 189
   16     INTEREST ON CUSTOMER DEPOSITS                                              68,985             68.130             855
   17     DEPRECIATION AND AMORTIZATION EXPENSE                                  75,569,475         74,395,233        1,174,242
   18     TAXES OTHER THAN INCOME                                                58,804,807         58.172,965         631,842
          CURRENT INCOME TAXES
   19      FEDERAL INCOME TAX                                                   118,847,134        115,799,865        3,047,269
   20      STATE INCOME TAX                                                          (37,732)          (36,613)          (1,119)
   21     CURRENT INCOME TAXES                                                  '118.809,402       115,763,252        3,046,150
          PROVISION FOR DEFERRED INCOME TAXES
   22      PROVISION FOR DEFERRED INCOME TAXES - FEDERAL                         14,962,189         14,502,193          459,995
   23      PROVISION FOR DEFERRED INCOME TAXES - STATE                               84.347             81,846            2,501
   24     PROVISION FOR DEFERRED INCOME TAXES                                    15,046,536         14,584,039          462,496
   25     INVESTMENT TAX CREDITS A/C 411                                         (1,657,606)         (1,627,189)        (30,417)
   26    TOTAL OPERATING EXPENSES                                               460,474,258        449,744,074       10,730,184
Blank Page
                                                                                                                                                                                     Attachment KJN--2


                                                                         Fuel Reconciliation Cost Adjustment Summary

                                          Spindletop Storage Facility Operating Costs                                                                       Line Loss Costs
                                                                                 Storage                Cities
            Payments to                                        ETI Eligible    Withdrawals            Proposed       Difference in                                            Difference in         Total
              Storage          Cost Allocation to Inventory      Storage           and                 Storage         Storage              ETI Allocated  Cities Allocated    Line Loss          Difference
             Operator           Injections     Withdrawals       Fuel Cost     Adjustments            Fuel Cost       Fuel Cost               Fuel Cost        Fuel Cost       Fuel Cost
                                                                                                                                                                          -
   Jul-09       190,586                    0         68,341          258,927       (967,954}             193,591           (65,336}             60,508,694      60,309,479        (199,215}           (264,551}
  Aug-09        458,607               (7,636)              0         450,971       (910,787)             182,157         (268,814}              47,892,586      47,734,672        (157,913)           (426,727)
  Sep-09        277,203                 (637)              0         276,566       (809,549)             161,910         (114,656)              38,132,827      38,007,278        (125,549)           (240,20:;)
  Oct-09        586,214             (17,862)               0         568,352       (675,482)             135,096         (433,256)              39,860,472      39,729,460        (131,012}           (564,267)
  Nov-09        558,364                    0         28,091          586,455       (328,023)               65,605        (520,850)              34,608,184      34,494,283        (113,901}           (634,751}
  Dec-09               0                   0         46,849           46,849       (642,533}             128,507            81,658              53,047,070      52,872,626        (174,444)             (92,787)
  Jan-10        346,088             (34,181)               0         311,907       (402,070}               80,414        (231,493}              68,250,582      68,026,673        (223,909)           (455,402}
  Feb-10        623,341                    0         14,501          637,842       (340,204)               68,041        (569,801}              53,105,832      52,931,070        (174,762)           (744,564)
  Mar-10        185,536                    0         32,417          217,953       (352,558}               70,512        (147,441}              37,225,005      37,102,516        (122,489)           (269,930)
  Apr-10        406,932                    0         37,736          444,668       (650,919}             130,184         (314,484)              33,053,739      32,945,129        (108,610)           (423,094)
  May-10        568,957               (9,251)              0         559,706       (761,151}             152,230         (407,476)              54,062,212      53,884,276        (177,936}           (585,412}
  Jun-10        490,857             (14,285}               0         476,572       (828,524)             165,705         (310,867)              68,342,777      68,118,429        (224,348}           (535,215}
   Jul-10       733,329                    0         36,424          769,753     (1,248,176)             249,635         (520,118}              70,356,347      70,124,901        (231,446)           (751,563}
  Aug-10        113,151                 (948)              0         112,203     (1,000,525)             200,105            87,902              81,934,891      81,665,245        (269,646}           (181,744)
  Sep-10        430,021             (10,608}               0         419,413       (715,348)             143,070         (276,343}              49,869,341      49,705,504        (163,837)           (440,180)
  Oct-10        426,185                    0         23,354          449,539       (831,584}             166,317         (283,222)              25,631,179      25,546,682          (84,497}          (367,719}
  Nov-10        446,619             (13,251)               0         433,368       (413,276)               82,655        (350,713}              31,317,885      31,214,945         (102,940)          (453,653)
  Dec-10        132,759               (2,090)              0         130,669       (288,652}               57,730          (72,939)             45,737,661      45,587,106         (150,555)          (223,493}
  Jan-11         341,006              (2,683)              0         338,323       (411,742)               82,348        (255,975)              51,829,772      51,659,579        {170,193)           (426,168)
  Feb-11         603,212                   0          9,325          612,537       (601,934)              120,387        (492,150)              48,624,815      48,464,956         (159,859)          (652,009)
  Mar-11         699,044            (31,317)               0         667,727       (580,673)              116,135         (551,592}             45,801,902      45,651,389        {150,512}           (702,105}
  Apr-11        537,836                    0         68,838          606,674       (766,831)              153,366         (453,308}             42,429,275      42,289,625         (139,650}          (592,958}
  May-11        555,439                    0         19,245          574,684       (827,689}              165,538         (409,146)             60,993,800       60,793,134        (200,666)          (609,812}
  Jun-11         291,458                   0         18,547          310,005       (874,174)              174,835         (135,170)             67,998,268       67,774,884        (223,384)          (358,554)

               10,002,744         (144,749)        403,668      10,261,663     (16,230,358)            3,246,072       (7,015,591)          1,210,615,116    1,206,633,845      (3,981,271)       (10,996,863)
Using Exhibit KDM 12 totals:                                                   {'.l,$1,1°Jl&!i>3} '    3)666,313 /          ,.J,<l::l\Jt;                                                      0'~'~1')5i1();s:~ir.
Blank Page
                                 Attachment KJN-3



HIGHLY SENSITIVE: CONFIDENTIAL




TEST-YEAR CAPACITY COSTS
Blank Page
                                 Attachment KJN-4



HIGHLY SENSITIVE: CONFIDENTIAL




RATE-YEAR CAPACITY COSTS
                             ENTERGY TEXAS, INC.
                     PUBLIC UTILITY COMMISSION OF TEXAS
                          SOAH DOCKET NO. 4 73-12-2979
                     PUC DOCKET NO. 39896 - 2011 ETI Rate Case

 Response of: Entergy Texas, Inc.                   Prepared By: Subparts "a through "f'
                                                    Counsel; Subparts "g" and "h" Kelly
                                                    Louque
to the Third Set of Data Requests                   Sponsoring Witness: Subparts "a through
                                                    "f' NIA; Subparts "g" and "h" Patrick
                                                    Cicio
of Requesting Party: Cities                         Beginning Sequence No.
                                                    Ending Sequence No.

 Question No.: Cities 3-3                         Part No.:                Addendum:

Question:

      In reference to the proposed sale of the Entergy transmissions assets to ITC
Holdings, please provide the following fonnation:

        a.      A copy of the current agreement of sale;

        b.     A copy of all due diligence analyses performed by or on behalf of Entergy
               evaluating the sale;

        c.     The current expected or estimated date for completion of the proposed
               transaction;

        d.     The total proceeds expected to be received by Entergy from the proposed
               transaction;

       e.      The book value of transmission assets to be sold under the transaction;

       f.      The book value of transmission assets located in Texas that are to be sold
               under the proposed transaction;

       g.      The total MSS-2 charges to all Entergy operating companies for each of
               the past five years 2006-2010 and the test year in this case;

       h.      The total MSS-2 charges to Entergy Texas for each of the past five years
               2006-2010 and for the test year.


Response:

ETI objects to this RFI because it seeks information or data that is not relevant to the
Company's pending request for relief and is therefore outside the scope of this
proceeding. Parties and the Commission will have a full opportunity to review issues




 39896                           CITIES' EXHIBIT 28                          Cities 3-3 LR154
'   Question No.: Cities 3-3

    relating to the Company's plan to transfer its electric transmission business to ITC
    Holdings Corp. in a future, separate proceeding requesting approval of that proposed
    transaction. ETI is not seeking any relief or approval associated with that proposed
    transaction in the instant proceeding. Notwithstanding this objection, and without
    waiving the same, ETI provides the following response:


    (a)      See the Company's response to State 1-6.
    (b)      The Company has filed an objection to this request.
    (c)      As disclosed in the December 5, 2011 press release, the transaction is expected to
             close by the end of 2013.
    (d)      See the Company's response to TIEC 1-48.
    (e)      See the Company's response to State 1-6. Refer to the Form 8-K filed December
             6, 2011, Item 1.01. Entry into a Material Definitive Agreement, Separation
             Agreement.
    (f)      See(e)above.
    (g)      Please see the attached.
    (h)      See (g) above.




     39896                                                                     Cities 3-3 LR155
PUCT Docket 39896
Cities 3·3 (g)

Entergy Operating Companies MSS-2 payments/{receipts) for the years 2006 • 2011
Credits reflect revenue (receipts); Debits reflect expense (payments)

Year                            EAi                EGSJ                  ELL                    EGSL            EMI                ENCi          ETI
2006                     $      7,691,868           (2,649,584)            (8,111,212)                      $    (1,971,870) $       5,040,797
2007                            2,204,469            5,882,997            {6,856,050)                            (5,962,975)         4,731,559
2008                           {1,415,587)                                (7,837,669)           11,762,725       (5,653,578)         5,804,604   (2,660,494)
2009                           (3,812,177)                                (7,896,585)            9,427,916       (3,532,269)         6,773,517     (960,402)
2010                           {4,909,612)                                (7,424,245)            7,377,010       {3,835,941)         8,233,158      559,630
2011"                          (2,104,269)                                (1,691,230)            1,515,163       (3,400,589)         4,331,993    1,348,932
Grand Total             $      {2,345,309) $         3,233,413    $      (39,816,991) $         30,082,815 $    (24,357,222) $      34,915,628   (1,712,334)

•2011 includes January -June 2011

Entergy Operating Companies MSS·2 payments/{ receipts) for the test year July 2010 ·June 2011
Credits reflect revenue (receipts); Debits reflect expense {payments)

                               EAi                  ELL                 EGSL                    EMI             ENO!                ETI
7/2010. 6/2011          $      (4,169,001) $         (4,738,043) $        3,955,371   $         {5,329,599) $     8,527,476   $      1,753,797




              39896                                                                                                               Cities 3-3 LR156
                                                                     CITIES' EXHIBIT 29


                             ENTERGY TEXAS, INC.
                     PUBLIC UTILITY COMMISSION OF TEXAS
                          SOAH DOCKET NO. XXX-XX-XXXX
                     PUC DOCKET NO. 39896 - 2011 ETI Rate Case

 Response of: Entergy Texas, Inc.                   Prepared By: Frances Grant/Rachelle
                                                    Hayes
 to the Fifth Set of Data Requests                  Sponsoring Witness: Robert R. Cooper/
                                                    Patrick Cicio
 of Requesting Party: Cities                        Beginning Sequence No.
                                                    Ending Sequence No.

 Question No.: Cities 5-1                         Part No.:                    Addendum: 2

 Question:

        In reference to Mr. Cicio's direct testimony at page 8 of75, lines 19-23, through
page 9, lines 1-11, please provide:

          a.   A complete and detailed explanation outlining how the system does its
               joint planning of generation resources;

          b.   List all the factors that go into the joint plan ofresources;

          c.   Provide copies of the most recent three joint resource plans;

        d.     Provide monthly peaks coincident with the System for each of the
               operating companies for the past five years 2006-2010 and all the months
               available in 2011 that are employed in the joint planning process;

       e.      Provide a list of generating resources for each operating company showing
               Mw capability for each resource by month for calendar 2010 and test year
               and rate year;

       f.      Provide a list of all firm purchase capability available to each operating
               company showing Mw capability for each resource purchase by month for
               calendar 2010, test year and rate year;

       g.      Provide the current load forecast for each operating company;

       h.      Provide the current system estimate long or short resources for each
               system operating company.


Response:

In response to several data requests in this set, Entergy Texas is providing a copy of the
Intra-System Bill (ISB) for January 2006 through November 2011. We will reference the
responsive Attachment number for each subsequent inquiry. See the attached public CD.

  39896                                      1                    CITIES 5-1ADDENDUM2 KH1587
Question No.: Cities 5-1 Addendum 2



        a.    Please see the response to Cities 1-36.

        b.    Please see the response to Cities 1-36.

        c.    Please see the response to Cities 1-36.

        d.    See Attachment 4 of the ISBs for Monthly Coincident Peaks.

        e.   The Company objects to this request on grounds that the responsive
             materials are highly sensitive protected ("highly sensitive") materials.
             Specifically, the responsive materials are protected pursuant to Texas
             Government Code Sections 552.101, 552.104 and/or 552.110. Highly
             sensitive materials will be provided pursuant to the terms of the Protective
             Order in this docket.

             See attachment 5 section (A) of the ISBs for owned generating resources
             with MW. Please also see the attached Highly Sensitive CD for
             supporting workpapers.

      f.     The Company objects to this request on grounds that the responsive
             materials are highly sensitive protected ("highly sensitive") materials.
             Specifically, the responsive materials are protected pursuant to Texas
             Government Code Sections 552.101, 552.104 and/or 552.110. Highly
             sensitive materials will be provided pursuant to the terms of the Protective
             Order in this docket.

             See Attachment 5 sections (B) and (D) of the ISBs for purchased
             capability with MW. Please also see the attached Highly Sensitive CD for
             supporting workpapers.

     g.      The Company objects to this request on grounds that the responsive
             materials are highly sensitive protected ("highly sensitive") materials.
             Specifically, the responsive materials are protected pursuant to Texas
             Government Code Sections 552.101, 552.104 and/or 552.110. Highly
             sensitive materials will be provided pursuant to the terms of the Protective
             Order in this docket.

             See the attached Highly Sensitive CD.
             "FEA12l_Firm_NonCoin_Pks_xBrazos_HSPI.xls" contains the current
             long-term forecast for each operating company's annual firm peak, non-
             coincident to the system. AECC load is not included.

     h.      Please see the response to Cities 1-36.




39896                                      2                   CITIES 5-1 ADDENDUM 2 KHl 588
Question No.: Cities 5-1Addendum2


Addendum 1:

Please see the attached public CD containing the December 2011 Intra-System Bill
(!SB).

Addendum 2:

See the attached ISBs for January and February 2012.




 39896                                    3                  CITIES 5-1ADDENDUM2 KH1589
 Entergy Electric System                            Date range -20100101through20100131                                                            Attachment 5
 Intra-System Billing-201001RA               Service Schedule MSS ~ 21 Transmission Equalization                                                        Page 46



                                                            AR              LA                MS               NO            EGSL                ETI
           Total Investment                            410,205,414.53 494,272,097.89 260,087,078.50 31, 189,868.31       320,330,456.87 214,793,237.35
           Deferred Taxes                               36,427.497.00 58,284,456.00 31,434,045.00 3,238,453,00            28,094,818.00 19,886,865.00
           Depreciation Reserve                        159,055,766.00 175,602,699.00 92,625,850.00 14,199,888.00         161,930,338,00 57,270,189.00
           Net Transmission Investment                 214,722,151.53260,384,942.89136,027,183.50 13,751,527.31          130,305,300,87 137,636,183.35

           Cost of Capital
             Debt Ratio (DR)                                0.477800        0.497100         0.484800         0.453100        0.478900          0.486400
             Bond Cost (I)                                  0.061400        0.068000         0.061900         0.060800        0.058700          0.053500
             Preferred Ratio {PR)                           0.039500        0.022700         0.035800         0.047300        0.003600
             Preferred Cost (p)                             0.059900        0.075800         0.056900         0.048200        0.087100
             Common Ratio (ER)                              0.482700        0.480200         0.479400         0.499600        0.517500          0.513600
             Common Cost (c)                                0.110000        0.110000         0.110000         0.110000        0.110000          0.110000
             Total Cost of Capital (CM)                     0,084800        0.088346         0.084780         0.084784        0.085350          0.082518

          Tax Rate (F)                                      0.035797       0.034112          0,033927         0,035796        0.035798          0.030421

          Operating Expenses
             Depreciation Factor (D)                      0.0148650       0.0280260         0.0225760        0.0282250       0.0198170        0.0200000
             Insurance Expense (I)                                        0.0043880         0.0040920                        0.0062920        0.0008440
             Property Tax (PT)                            0.0045360       0.0091200         0.0174110        0.0112200       0.0085080        0.0075140
             Franchise Tax (FT)                           0.0000490                         0.0010150        0.0014940      (0.0000140)       0.0014770
             Operations & Maintenance (OM)                0.0377920       0.0420730         0.0351650        0.0475470       0.0509460        0.0343280
             Total Operating Expenses                     0.0572420       0.0836070         0.0802590        0.0884860       0.0855490        0.0641630

          Net Investment Ratio (K)                         0.523450        0.526805          0.523006         0.440897       0.406784           0.640785

          Annual Ownership Cost                            0.229952        0.281163          0.272164         0.321275       0.331453           0.213070

          Net Transmission Investment* AOC             49,375,788.00 73,210,612.00 37,021,702.00           4,418,022.00 43,190,083.00 29,326, 142.00

          System Average Annual Ownership Cost        236,542,349.00 I           892,827,289.45              0.2649363

          System Average Monthly Ownership Cost                                       0.2649363     I 12     0.0220780

          Responslbillty Ratio                                0.2100             0.2600           0.1389        0.0450         0.1920             0.1541

          Transmission Responsibility                 187,493,730.78 232,135,095.26 124,013,710.50 40, 177,228.03 171,422,839.57 137,584,685.30

          Investment Difference                        27,228,420.75 28,249,847.63 12,013,473.00 (26,425,700.72)(41, 117,538.70)               51,498.05

          Payments                                                                                          583,427.26     907,794,01

          Receipts                                       601,149.73      623,700.82        265,233.75                                           1,136.98




Attachment Snapshct: 20101)223192132                              Runro: 16123                                                      Bllllng Snapshot: 20100223183926




                                                                           4
 Entergy Electric System                            Date range· 20100201 through 20100228                                                         Attachment 5
 Intra-System Bllling-201002RA               Service Schedule MSS • 2 I Transmission Equalization                                                         Page 39



                                                            AR               LA                MS               NO            EGSL              ETI

          Total Investment                             410,284,549.48 494,946,439.93 260,055,826.87 31, 189,868.31        320,881,450.31 214,892,263.91
          Deferred Taxes                                36,427,497.00 58,284,456.00 31,434,045.00 3,238,453.00             28,094,818.00 19,888,865.00
          Depreciation Reserve                         159,055,766.00175,602,699.00 92,625,850.00 14,199,888.00           161,930,338.00 57,270,189.00
          Net Transmission Investment                  214,801,286.48 261,059,284.93 135,995,931.87 13,751,527.31         130,856,294.31 137,735,209.91

          Cost of Cap!tal
            Debt Ratio {DR}                                 0.477800        0.497100          0.484800         0.453100       0.478900         0.486400
            Bond Cost (i)                                   0.061400        0.068000          0.061900         0.060800       0.058700         0.053500
            Preferred Ratio (PR)                            0.039500        0.022700          0.035800         0.047300       0.003600
            Preferred Cost (p)                              0.059900        0.075800          0.056900         0.048200       0.087100
            Common Ratio (ER)                               0.482700        0.480200          0.479400         0.499600       0.517500         0.513800
            Common Cost (c)                                 0.110000        0.110000          0.110000         0.110000       0.110000         0.110000
            Total Cost of Capital (CM)                      0.084800        0.088346          0.084780         0.084784       0,085350         0.082518

          Tax Rate (F)                                      0.035797        0.034112          0.033927         0.035798       0.035798         0.030421

          Operating Expenses
            Depreciation Factor (D)                        0.0148650      0.0280260          0.0225760        0.0282250      0.0198170        0.0200000
            Insurance Expense (I)                                         0.0043880          0.0040920                       0.0062920        0.0008440
            Property Tax (PT)                             0.0045360       0.0091200          0.0174110        0.0112200      0.0085080        0.0075140
            Franchise Tax (FT)                            0.0000490                          0.0010150        0.0014940     (0.0000140)       0.0014770
            Operations & Maintenance (OM)                 0.0377920       0.0420730          0.0351650        0.0475470      0.0509460        0.0343280
           Total Operating Expenses                       0.0572420       0.0836070          0.0802590        0.0884860      0.0855490        0.0641630

          Net Investment Ratio (K)                          0.523542        0.527450          0.522949         0.440897       0.407803         0.640950

          Annual Ownership Cost                            0.229933        0.280969           0.272180         0.321275       0.330928         0.213045

          Net Transmission Investment *AOC             49,389,904.00 73,349,566.00 37,015,373.00            4,418,022.00 43,304,012.00 29,343,798.00

          System Average Annual Ownership Cost        236,820,675.00 I           894, 199,534.81              0.2648410

          System Average Monthly Ownership Cost                                       0.2648410      112      0.0220701

          Responsibility Ratio                                0.2100             0.2610            0.1384        0.0454         0.1894           0.1558

          Transmission ResponslbJ!ity                 187,781,902.31 233,386,078.59123,757,215.62 40,596,658.88 169,361,391.89 139,316,287.52

          Investment Difference                        27,019,384.17 27,673,206.34 12.238,716.25 (26,845,131.57) (38,505,097.58) (1,581 ,077.61)

          Payments                                                                                           592,474.23     849,810.63        34,894.51

          Receipts                                       596,320.00      610,749.91         270,109.46




Attachment Snapshlt: 20100327200632                               RunlO: 16439                                                     Biiiing Snapshot: 20100327200632




                                                                           5
 Entergy Electric System                           Date range. 20100301 through 20100331                                                          Attachment 5
 Intra-System Billing-201003RA               Service Schedule MSS • 21 Transmission Equalization                                                       Page 44



                                                            AR              LA                MS               NO           EGSL               ETI

          Total Investment                             410,321,729.39 515,491,730.27 265,915,679.32 27,047,831.26 323,328,537,13 216,671,976.21
          Deferred Taxes                                36,427,497.00 58,284,456.00 31,434,045.00 3,238,453.00 28,094,818.00 19,886,865.00
          Depreciation Reserve                         159,055,766.00 175,602,699.00 92,625,850,00 14,199,888.00 161,930,338.00 57,270,189,00
          Net Transmission Investment                  214,838,466.39 281,604,575.27 141,855,784.32 9,609,490.26 133,303,381.13 139,514,922.21

          Cost of Capita!
            Debt Ratio (DR)                                 0.477800        0.497100         0.484800         0.453100       0.478900          0.486400
            Bond Cost (I)                                   0.061400        0.068000         0.061900         0.060800       0.058700          0.053500
             Preferred Ratio (PR)                           0.039500       0.022700          0.035800         0.047300       0.003600
             Preferred Cost (p)                             0.059900        0.075800         0.056900         0.048200       0.087100
             Common Ratio {ER)                              0.482700        0.480200         0.479400         0.499600       0.517500          0.513600
             Common Cost {c)                                0.110000      '0.110000          0.110000         0, 110000      0.110000          0.110000
             Total Cost of Capital (CM)                     0.084800        0.088346         0.084780         0.084784       0.085350          0.082518

          Tax Rate (F)                                      0.035797       0,034112          0.033927         0.035796       0.035798          0.030421

          Operating Expenses
             Depreciation Factor {D)                      0.0148650       0.0280260         0,0225760        0.0282250      0,0198170        0.0200000
             Insurance Expense (I)                                        0.0043880         0.0040920                       0.0062920        0.0008440
             Property Tax (PT)                            0.0045360       0.0091200         0.0174110        0.0112200      0.0085080        0.0075140
             Franchise Tax (FT)                           0.0000490                         0.0010150        0.0014940     (0.0000140)       0.0014770
             Operations & Maintenance {OM)                0.0377920       0.0420730         0.0351650        0,0475470      0.0509460        0.0343280
             Total Operating Expenses                     0.0572420       0.0836070         0.0802590        0,0884860      0.0855490        0.0641630

          Net Investment Ratio (K)                         0.523585        0.546283          0.533462         0.355278      0.412285          0.643899

          Annual Ownership Cost                            0.229924        0.275505          0.269156         0,369641      0.328647          0.212586

          Net Transmission Investment* AOC             49,396,520.00 77,583,469,00 38,181 ,335.00          3,552,062.00 43,809,756.00 29,658,919.00

          System Average Annual Ownership Cost        242,182,061.00 I           920,726,619.58              0.2630336

          System Average Monthly Ownership Cost                                       0.2630336     112      0.0219195

          Respcnslblllty Ratio                                0.2099             0.2604           0.1376        0.0455         0, 1882           0. 1584

          Transmission Responsibility                 193,260,517.45 239,757,211.74 126,691,982.85 41,893,061, 19 173,280,749.80 145,843,096.54

          Investment Difference                        21,577,948.94 41,847,363.53 15, 163,801.47 (32,283,570.93) (39,977,368.67) (6,328, 174.33)

          Payments                                                                                          707,638.73    876,282.69        138,710.22

          Receipts                                       472,977.18      917,271.98        332,382.47




Attachment Snapshct: 20100427145'432                              RunlD: 15724                                                     Bll!lng Snapshot: 201004Zl145432




                                                                           6
 Entergy Electric System                           Date range - 20100401 through 20100430                                                         Attachment 5
 Intra-System 8illing-201004RA               Service Schedule MSS • 2 /Transmission Equalization                                                       Page 4o



                                                            AR              LA                 MS              NO           EGSL                ETI
          Total Investment                             410,959,209.58515,178,314.04       267,631,740,26 27,048,535.93 331,250,005.35 216,613,685,21
          Deferred Taxes                                36,427,497.00 58,284,456.00        31,434,045.00 3,238,453.00 28,094,818.00 19,886,865.00
          Depreciation Reserve                         159,055,766.00 175,602,699.00       92,625,850.00 14, 199,888.00 161,930,338.00 57,270, 189,00
          Net Transmission Investment                  215,475,946.58281,291,159.04       143,571,845.26 9,610, 194.93 141,224,849.35 139,456,631.21

          Cost of Cap!tal
            Debt Ratio (DR)                                0.477800         0.497100          0.484800        0.453100       0.478900          0.486400
            Bond Cost (i)                                  0.061400         0.068000          0.061900        0.060800       0.058700          0.053500
            Preferred Ratio (PR)                           0.039500         0.022700          0.035800        0.047300       0.003600
            Preferred Cost (p)                             0.059900         0.075800          0.056900        0.048200       0.087100
            Common Ratio (ER)                              0.482700         0.480200          0.479400        0.499600       0.517500          0.513600
            Common Cost (c)                                0.110000         0.110000          0.110000        0.110000       0.110000          0.110000
            Total Cost of Capllal (CM}                     0.084800         0.088346          0.084780        0.084784       0.085350          0.082518

          Tax Rate (F)                                      0.035797        0.034112          0.033927        0.035796       0.035798          0.030421

          Operating Expenses
            Depreciation Factor (D)                       0.0148650       0.0280260          0.0225760       0.0282250      0.0198170        0.0200000
            Insurance Expense (J)                                         0.0043880          0.0040920                      0,0062920        0.0008440
            Property Tax (PT}                             0.0045360       0.0091200         ·0.0174110       0.0112200      0.0085080        0.0075140
            Franchise Tax (FT)                            0.0000490                          0.0010150       0.0014940     (0.0000140)       0.0014770
            Operations & Maintenance {OM)                 0.0377920       0.0420730          0.0351650       0.0475470      0.0509460        0.0343280
            Total Operating Expenses                      0.0572420       0.0836070          0.0802590       0.0884860      0.0855490        0.0641630

         Net Investment Ratio (K)                          0.524324        0.546007           0.536453        0.355294      0.426339           0.643803

         Annual Ownership Cost                             0.229769        0.275582           0.268317        0.369630      0.321807           0.212601

         Net Transmission Investment'" AOC             49,509,693.00 77 ,518,780.00 38,522,767.00          3,552,216.00 45,447,145.00 29,648,619.00

         System Average Annual Ownership Cost         244, 199,220.00 I          930,630,626.37        =     0.2624019

         System Average Monthly Ownership Cost                                        0.2624019     / 12     0.0218668

         Responsibility Ratio                                0.2080              0.2609           0.1372        0.0457         0.1881            0.1601

         Transmission Responslbl!ity                  193,571,170.28 242,801,530,42 127,682,521.94 42,529,819.63 175,051,620.82 148,993,963.28

         Investment Difference                         21,904,776.30 38,489,628.62 15,889,323.32 (32,919,624.70) (33,826,771.47) (9,537,332.07)

         Payments                                                                                           719,847.60    739,684.02        208,551.15

         Receipts                                        478,987.86       841,645.89        347,449.02




AttachmentSnapshO:: 2D100526143752                                RunlO: 16029                                                     Bill!ng Snapshot: 20100526143752




                                                                           7
 Entergy Electric System                            Date range-20100501through20100531                                                               Attachment 5
 Intra-System Billing-201005RA                Service Schedule MSS - 21 Transmission Equalization                                                            Page 42



                                                             AR                LA                MS               NO           EGSL                ETI
           Total Investment                             411,217,204.18 515,213, 187.86 270,079,411. 77 27 ,048, 703.26 331,270, 197 .89 222,210,473,94
           Deferred Taxes                                36,427,497.00 58,284,456.00 31,434,045.00 3,238,453.00 28,094,818.00 19,886,865.00
           Depreciation Reserve                         159,055,766.00 175,602,699.00 92,625,850,00 14, 199,888.00 161,930,338.00 57,270, 189,00
           Net Transmission Investment                  215,733,941.18 281,326,032.86 146,019,516.77 9,610,362.26 141,245,041.89 145,053,419.94

           Cost of Capital
             Debt Ratio (DR)                                 0.477800          0.497100         0.484800         0.453100       0.478900          0.486400
             Bond Cost (J)                                   0.061400          0.068000         0.061900         0.060800       0.058700          0.053500
             Preferred Ratio (PR)                            0.039500          0.022700         0.035800         0.047300       0.003600
             Preferred Cost (p)                              0.059900          0.075800         0.056900         0.048200       0.087100
             Common Ratio (ER)                               0.482700          0.480200         0.479400         0.499600       0.517500          0.513600
             Common Cost (c)                                 0.110000          0.110000         0.110000         0.110000       0.110000          0.110000
             Total Cost of Capita! (CM)                      0.084800          0.088346         0.084780         0.084784       0.085350          0.082518
           Tax Rate (F)                                      0.035797         0.034112          0.033927         0.035796      0.035798           0.030421
           Operating Expenses
             Dapraclatlon Factor (D)                       0.0148650         0.0280260         0.0225760        0.0282250      0.0198170        0.0200000
             Insurance Expense (I)                                           0.0043880         0.0040920                       0.0062920        0.0008440
             Property Tax (PT)                             0.0045360         0.0091200         0.0174110        0.0112200      0,0085080        0.0075140
             Franchise Tax (FT)                            0.0000490                           0.0010150        0.0014940     (0.0000140)       0.0014770
             OperaUons & Malntenance (OM)                  0.0377920         0.0420730         0.0351650        0.0475470      0.0509460        0.0343280
             Total Operating Expenses                      0.0572420         0,0836070         0.0802590        0.0884860      0.0855490        0.0641630

           Net Investment Ratio {K)                          0.524623         0.546038          0.540654         0.355298      0.426374           0.652775

          Annual Ownership Cost                              0.229707         0.275573          0.267154         0,369627      0.321791           0.211231

           Net Transmission Investment* AOC             49,555,596.00 77,525,859.00 39,009,698.00             3,552,249.00 45,451,383.00 30,639,779.00

          System Average Annual Ownership Cost         245, 734,564.00 I            938,988,314.90              0.2617014

           System Average Monthly Ownership Cost                                         0.2617014     / 12     0,0218084

           Responslbf!ity Ratio                                0.2088               0.2597           0.1363        0.0456        0.1887             0.1609

          Transmission Respons!bllity                  196,060,760.15 243,855,265.38 127,984,107.32 42,817,867.16 177,187,095.02 151,083,219.87

          Investment Difference                         19,673, 181.03 37,470,767.48 18,035,409.45 (33,207,504.90) (35,942,053.13) (6,029,799.93)

          Payments                                                                                             724,204.23    783,840.49        131,500.59

          Receipts                                        429,041.60       817,179.38         393,324.34




Attachment Snapshct: 201006261114103                              . -Run!O: 16341                                                     Biiiing Snapshot: 20100625173239




                                                                              8
 Entergy Electric System                            Date range - 20100601 through 20100630                                                         Attachment 5
 Intra-System Billing-201006RA               Service Schedule MSS ~ 2 I Transmission Equalization                                                       Page 44



                                                            AR               LA                 MS              NO           EGSL                ETI
          Tota! Investment                             411,270,947.16 516,493,136.74 270,353,906.99 27,048,703.25 331,881,485.90 242,644,575.63
          Deferred Taxes                                37,430,361.00 58,063,215.00 30,006,678.00 3,089,864,00 25,629,920.00 19, 783,447.00
          Depreciation Reserve                         162,587,708.00 186,714,652.00 98,019,787.00 14, 138,861.00 167 ,174,252.00 61,398,531.00
          Net Transmission Investment                  211,252,878.16 271,715,269.74 142,327,441.99 9,819,978.25 139,077,313.90 161,462,597.63

          Cost of Cap!tal
            Debt Ratio {DR)                                 0.476500        0.502800            0.527000       0.455600       0.491300          0.483500
            Bond Cost (i)                                   0.061600        0.067100           0.063400        0.060700       0.060900          0.075100
            Preferred Ratio {PR)                            0.039300        0.019900           0.031800        0,047700       0.003200
            Preferred Cost (p)                              0.059900        0.075500           0.056900        0,048200       0.087100
            Common Ratio (ER)                               0.484200        0.477400           0.441200        0.496700       0.505500          0.516500
            Common Cost (c)                                 0.110000        0.110000           0.110000        0.110000       0.110000          0.110000
            Total Cost of Capita! (CM)                      0.084968        0.087754           0.083753        0.084591       0.085804          0.093126

          Tax Rate (F)                                      0.035895        0.033783           0.031183        0.035609       0.034951          0.030593

          Operat!ng Expenses
            Depreciation Factor (D}                        0.0153010       0.0271140          0.0229240       0.0277360      0.0202970        0.0197710
            Insurance Expense (I)                          0.0038030       0.0011480          0.0038520                      0,0021750        0.0018310
            Property Tax (PT)                              0.0043820       0.0082710          0.0166890       0.0121940      0.0067670        0.0074320
            Franchise Tax (FT)                             0.0001530                          0.0010110       0.0020450                       0.0008500
            Operations & Maintenance (OM}                  0.0351800       0.0374620          0.0356540       0.0424620      0.0448010        0.0263850
            Total Operating Expenses                       0.0588190       0.0739950          0.0801300       0.0844370      0.0740400        0.0562690

          Net Investment Ratio (K)                          0.513659        0.526077           0.526449        0.363048       0.419057          0.665428

          Annual Ownership Cost                             0.235372        0.262191           0.267144        0.352778       0.297437          0.208279

          Net Transmission Investment* AOC             49,723,012.00 71,241,298.00 38,021,922.00            3,464,272.00 41,366, 739.00 33,629,268.00

          System Average Annual Ownership Cost         237,446,511.00 I           935,655,479.67              0.2537756

          System Average Monthly Ownership Cost                                        0.2537756     / 12     0.0211480

          Respons!b!llty Ratio                                0.2100              0.2594           0.1366        0.0455         0.1874             0.1611

          Transmission Responsibility                  196,487,650.73 242,709,031.43 127,810,538.52 42,572,324.32 175,341,836,89 150,734,097.77

          Investment Difference

          Payments
                                                       14,765,227.43 29,006,238.31         14,516,903.47 (32,752,346.07) (36,264,522.99) 10,728,499,86

                                                                                                             692,645.47     766,920.86
                                                                                                                                                                       I
          Receipts                                        312,254.51      613,422.91         307,002.97                                      226,885.94




AttachmentSnapshd!: 20100728092959                                 RimlD: 16707                                                     Bllllng Snapshot: 20100728092959




                                                                            9
 Entergy Electric System                           Date range· 20100701 through 20100731                                                            Attachment 5
 Intra-System Bllling-201007RA               Service Schedule MSS • 21 Transmission Equalization                                                          Page 44



                                                            AR               LA               MS               NO           EGSL               ETI

          Total Investment                             414,292,644.47 516,998,737.69 270,282,974.70 26,290,825.51 332,286,730.47 246,384,445.14
          Deferred Taxes                                37,430,361.00 58,063,215.00 30,006,678.00 3,089,864.00 25,629,920.00 19,783,447,00
          Depreciation Reserve                         162,587,708.00 186,714,652.00 98,019,787.00 14, 138,861.00 167,174,252.00 61,398,531.00
          Net Transmission Investment                  214,274,575.47 272,220,870.69142,256,509.70 9,062, 100.51 139,482,558.47 165,202,467.14

          Cost of Capital
            Debt Ratio (DR)                                 0.476500        0.502800         0.527000         0.455600       0.491300          0.483500
            Bond Cost (I)                                   0.061600        0.067100         0.063400         0.060700       0.060900          0.075100
            Preferred Ratio (PR)                            0.039300        0.019900         0.031800         0.047700       0.003200
            Preferred Cost {p}                              0.059900        0.075500         0.056900         0.048200       0.087100
            Common Ratio {ER)                               0.484200        0.477400         0.441200         0.496700       0.505500          0.516500
            Common Cost (c)                                 0.110000        0.110000         0. 110000        0.110000       0.110000          0.110000
            Total Cost of Capltal (CM)                      0.084968        0.087754         0.083753         0.084591       0.085804          0.093126

          Tax Rate {F)                                      0.035895        0.033783         0.031183         0.035609      0.034951           0.030593
          Operating Expenses
            Depreciation Factor (D}                       0.0153010       0.0271140         0.0229240        0.0277360     0.0202970         0.0197710
            Insurance Expense (l)                         0.0038030       0.0011480         0.0038520                      0.0021750         0.0018310
            Property Tax (PD                              0.0043820       0.0082710         0.0166890        0.0121940     0.0067670         0.0074320
            Franchise Tax (FD                             0.0001530                         0.0010110        0.0020450                       0.0008500
            Operations & Maintenance (OM)                 0.0351800       0.0374620         0.0356540        0.0424620     0.0448010         0.0263850
            Total Operating Expenses                      0.0588190       0.0739950         0.0801300        0.0844370     0.0740400         0.0562690

          Net Investment Ratio (K)                         0.517206         0.526541         0.526324         0.344687      0.419766          0.670507

          Annual Ownership Cost                             0.234587        0.262067         0.2671 BO        0.365167      0.297138          0.207639

          Net Transmission Investment* AOC             50,266,030,00 71,340, 107.00 38,008,094.00          3,309,180.00 41,445,568.00 34,302,475.00
                                                                                                                                                '
          System Average Annual Ownership Cost        238,671,454.00 I           942,499,081.98              0.2532326

          System Average Monthly Ownership Cost                                       0.2532326     / 12     0.0211027

          Responslbll!ty Ratio                                0.2108             0.2590           0.1370        0.0450        0.1853             0.1629

          Transmission Responsibility                 198,678,806.48 244,107,262.23 129, 122,374.23 42,412,458.69 174,645,079.89 153,533, 100.45

          Investment Difference                        15,595,768.99 28, 113,608.46 13,134, 135.47 (33,350,358.18) (35, 162,521.42) 11,669,366.69

          Payments                                                                                          703,783.04    742,024.61

          Receipts                                       329,113.04      593,273.42        277,165.89                                       246,255.30




Attachment Snapshd: 20100826181933                                Run10: 17029                                                     BIH!ng Snapshot: 20100826175230




                                                                          10
  Entergy Electric System                             Date range -20100801through20100831                                                            Attachment 5
  Intra-System Billing-201008RA                 Service Schedule MSS • 2 /Transmission Equalization                                                           Page 48



                                                               AR              LA                MS               NO           EGSL                ETI
           Total Investment                               414,756,346.25 517,198.430.56 273,055,871.75 26,286,818.76 346,877,541.44 248,054,884.20
           Deferred Taxes                                  37,430,361.00 56,063,215.00 30,006,676.00 3,089,864.00 25,629.920.00 19,783.447.00
           Depreciation Reseive                           162.587,708.00186,714,652.00 98,019,787.00 14,138,861.00 167,174,252.00 61,398,531.00
           Net Transmission Investment                    214,738,277.25 272.420,563.56 145;029.406.75 9,058,093.76 154,073,369.44166,872,906.20

           Cost of Cap!tar
             Debt Ratio (DR)                                  0.476500         0.502800         0.527000         0.455600       0.491300          0.483500
             Bond Cost (i)                                    0.061600         0.067100         0.063400         0.060700       0.060900          0.075100
             Preferred Ratio (PR)                             0.039300         0.019900         0.031800         0.047700       0.003200
             Preferred Cost (p)                               0.059900         0.075500         0.056900         0.048200       0.087100
             Common Ratio {ER)                                0.484200         0.477400         0.441200         0.496700       0.505500          0.516500
             Common Cost (c)                                  0.110000         0.110000         0.110000         0.110000       0.110000          0.110000
             Total Cost of Capital (CM)                       0.084968         0.087754         0.083753         0.084591       0.085804          0.093126
           Tax Rate (F)                                       0.035895         0.033783         0.031183         0.035609       0.034951          0.030593

           Operating Expenses
             Depreciation Factor (D)                         0.0153010       0.0271140         0.0229240        0.0277360      0.0202970        0.0197710
             Insurance Expense (I)                           0.0038030       0.0011480         0.0038520                       0.0021750        0.0018310
             Property Tax (PT)                               0.0043820       0.0082710         0.0166890        0.0121940      0.0067670        0.0074320
             Franchise Tax (FT)                              0.0001530                         0.0010110        0.0020450                       0.0008500
             Operations & Maintenance (OM)                   0.0351800       0.0374620         0.0356540        0.0424620      0.0448010        0.0263850
            Total Operating Expenses                         0.0588190       0.0739950         0.0801300        0.0844370      0.0740400        0.0562690

           Net Investment Ratio (K)                           0.517746        0.526723          0.531135         0.344587       0.444172          0.672726

           Annual Ownership Cost                              0.234468        0.262018          0.265801         0.365238       0.287447          0.207362

           Net Transmission Investment .. AOC             50,349,254.00 71,379,091.00 38,548,961.00           3,308,360.00 44,287,928.00 34,603, 100.00

           System Average Annual Ownership Cost          242,476,694.00 I           962,192,616.96              0.2520043

           System Average Monthly Ownership Cost                                         0.2520043     /12      0.0210004

           Responsibility Raflo                                 0.2118              0.2586           0.1376        0.0449         0.1830             0.1641

          Transmission Responsib!Hty                     203,792,396.27 248,823,010.75 132,397,704.09 43,202,448.50 176,081.248.90157.895.808.44

          Investment Difference                           10,945,880.98 23.597.552.81 12,631.702.66 (34,144,354.74) (22,007,879.46)          8,977,097.76

          Payments                                                                                             717,043.74     462,173.39

          Receipts                                          229,867.44      495,557.10        265,270.30                                       188,522.28




Attachment Snapshi:t: 2010092721202.1                                RunlD: 17306                                                     Biiiing Snapshot: 20100927145113




                                                                             11
 Entergy Electric System                             Date range - 20100901 through 20100930                                                        Attachment 5
 Intra-System Billing-201009RA                Service Schedule MSS • 2 I Transmission Equalization                                                      Page 43



                                                             AR               LA                MS              NO            EGSL               ETI

          Total Investment                              414,738,135.57 517,477,482.94 273,038,040.36 26,298,420.03 346,868,159,71 223,998,394.51
          Deferred Taxes                                 37,430,361.00 58,063,215.00 30,006,678.00 3,089,864.00 25,629,920.00 19,783,447,00
          Depreciation Reserve                          162,587,708.00 186,714,652.00 98,019,787.00 14, 138,861.00 167, 174,252.00 61,398,531,00
          Net Transmission Investment                   214,720,066.57 272,699,615.94145,011,575.36 9,069,695.03 154,063,987,71 142,816,416.51

          Cost of Capital
            Debt Ratio {DR)                                  0.476500        0.502800          0.527000         0.455600      0.491300           0.483500
            Bond Cost (i)                                    0.061600        0.067100          0.063400         0,060700      0.060900           0.075100
            Preferred Ratio {PR)                             0.039300        0.019900          0.031 BOO        0.047700      0.003200
            Preferred Cost {p)                               0,059900        0.075500          0.056900         0.048200      0.087100
            Common Ratio (ER)                                0.484200        0.477400          0.441200         0.496700      0.505500           0.516500
            Common Cost (c)                                  0.110000        0.110000          0.110000         0.110000      0. 110000          0.110000
            Total Cost of Capital (CM)                       0.084968        0.087754          0.083753         0.084591      0.085804           0.093126

          Tax Rate (F)                                       0.035895        0.033783          0.031183         0.035609      0.034951          0.030593

          Operating Expenses
            Depi-eciation Factor (D)                        0.0153010       0.0271140         0.0229240        0.0277360     0.0202970         0.0197710
            Insurance Expense (J)                           0.0038030       0.0011480         0.0038520                      0.0021750         0.0018310
            Property Tax (PT)                               0.0043820       0.0082710         0.0166890        0.0121940     0.0067670         0.0074320
            Franchise Tax (FT}                              0.0001530                         0.0010110        0.0020450                       0.0008500
            Operations & Maintenance (OM)                   0.0351800       0.0374620         0,0356540        0,0424620     0.0448010         0.0263850
            Total Operating Expenses                        0.0588190       0.0739950         0.0801300        0.0844370     0.0740400         0.0562690

          Net Investment Ratio (K)                           0.517724        0.526979          0.531104         0.344876      0.444157          0.637578

          Annual Ownership Cost                              0.234473        0.261950          0.265810         0,365032      0.287452          0.211973

          Net Transmission Investment"' AOC             50,346,058.00 71,433,664.00 38,545,527,00            3,310,729.00 44,286,001.00 30,273,224.00

          System Average Annual Ownership Cost          238,195,203.00 I           938,381,357.12              0.2538362

          System Average Monthly Ownership Cost                                         0.2538362     / 12     0.0211530

          Responsfbilily Ratio                                 0.2120              0.2588           0.1387        0.0449        0. 1826            0.1630

         Transmission Responsibility                    198,936,847.71 242,853,095.22 130,153,494.23 42, 133,322.93 171,348,435.81 152,956, 161.21

          Investment Difference                         15, 783,218.86 29,846,520.72 14,858,081 .13 (33,063,627.90) (17,284,448.10) (10, 139,744.70)

          Payments                                                                                            699,395.60    365,618.29        214,486.23

         Receipts                                          333,862.75      6311344.07        314,293.30




Attachment Snapshot: 20101027081939                                 Run!D: 17618                                                     BIUlng Snapshot: 20101026135839




                                                                            12
 Entergy Electric System                            Date range· 20101001through20101031                                                              Attachment 5
 Intra-System Bllling-201010RA                Service Schedule MSS - 21 Transmission Equalization                                                         Page 42



                                                             AR               LA                 MS               NO           EGSL                ET!

          Total Investment                              414,791,036,09 505,655,952.56 273,529,330.19 26,299,394.26 347,196,039.47 223,962,656.04
          Deferred Taxes                                 37,430,361.00 58,063,215.00 30,006,678.00 3,069,864.00 25,629,920.00 19,783,447.00
          Depreciation Reserve                          162,587,708.00 186,714,652.00 98,019,787.00 14, 138,861.00 167, 174,252.00 61,398,531.00
          Net Transmission Investment                   214,772,967.09 260,878,085,56145,502,865.19 9,070,669.26 154,391,867.47 142,780,678.04

          Cost of Capltal
            Debt Ratio (DR)                                  0.476500        0.502800           0.527000         0.455600       0.491300          0.483500
            Bond Cost (i)                                    0.061600        0.067100           0,063400         0.060700       0.060900          0.075100
            Preferred Ratio (PR)                             0.039300        0.019900           0.031800         0.047700       0.003200
            Preferred Cost (p)                               0.059900        0.075500           0.056900         0.048200       0.087100
            Common Ratio (ER)                                0.484200        0.477400           0.441200         0.496700       0.505500          0.516500
            Common Cost (c)                                  0.110000        0.110000           0.110000         0.110000       0.110000          0.110000
            To!al Cost of Capital (CM)                       0.084968        0.087754           0.083753         0.084591       0.085804          0.093126

          Tax Rate (F)                                       0.035895        0.033783           0,031183         0.035609       0.034951          0.030593

          Operating Expenses
            Depreclallon Factor (D)                        0.0153010        0.0271140          0.0229240        0.0277360      0.0202970        0.0197710
            Insurance Expense (I)                          0.0038030        0.0011480          0.0038520                       0.0021750        0.0018310
            Property Tax (PT)                              0.0043820        0.0082710          0.0166890        0.0121940      0.0067670        0.0074320
            Franchise Tax (FT)                             0.0001530                           0.0010110        0.0020450                       0.0008500
            Operations & Maintenance (OM)                  0.0351800        0.0374620          0.0356540        0.0424620      0,0448010        0.0263850
            Tota! Operating Expenses                       0.0588190        0.0739950          0.0801300        0.0844370      0.0740400        0.0562690

          Net Investment Ratio (K)                          0.517786         0.515920           0.531946         0.344900       0.444682          0.637520

          Annual Ownership Cost                             0.234460         0.264960           0.265571         0.365015       0.287256          0.211981

          Net Transmission Investment ~ AOC             50,355,670.00 69, 122,258.00 38,641,341.00            3,310,930.00 44,349,990.00 30,266, 791.00

          System Average Annual Ownership Cost         236,046,980.00 I            927,397' 132.61              0.2545263

          System Average Monthly Ownership Cost                                         0.2545263      /12      0.0212105

          Responsiblllty Ratio                                 0.2115              0.2601            0.1386        0.0450         0.1810            0.1638

          Transmission ResponsibUity                   196, 144,493.55 241,215,994.19 128,537,242.58 41,732,870.97 167,858,881.00 151,907,650.32

          Investment Difference                         18,628,473.54 19,662,091.37 16,965,622.61 (32,662,201. 71) (13,467,013.53) (9,126,972.28)

          Payments                                                                                             692,782.50     285,642.45       193,587.89

          Receipts                                        395,119.74      417,043.31          359,849.79




Attachment Snapshot: 20101124124641                                RunlO: 171161                                                      Bl!llng Snapshot: 201011Z4DB4S11




                                                                           13
 Entergy Electric System                           Date range· 20101101through20101130                                                             Attachment 5
 Intra-System Billing-201011 RA              Service Schedule MSS ~ 21 Transmission Equalization                                                        Page 40



                                                            AR              LA                MS              NO            EGSL                ETI

           Total Investment                            414,855,854.25 506,433,213.41 273,547,229.46 26,299,413.85 348,837,905.80 224,013,632.72
           Deferred Taxes                               37,430,361.00 58,063,215.00 30,006,678.00 3,089,864.00 25,629,920.00 19,783,447.00
           Depreclatlon Reserve                        162,587,708.00 186,714,652.00 98,019,787.00 14,138,861.00 167, 174,252.00 61,398,531.00
           Net Transmission Investment                 214,837,785.25 261,655,346.41145,520,764.46 9,070,688.85 156,033,733.80 142,831,654.72

          Cost of Capital
            Debt Ratio (DR)                                 0.476500       0.502800          0.527000         0.455600       0.491300           0.483500
            Bond Cost (I)                                   0.061600       0.067100          0.063400         0.060700       0.060900           0.075100
            Preferred Ratio (PR)                            0.039300       0.019900          0.031800         0.047700       0.0.03200
            Preferred Cost (p)                              0.059900       0.075500          0.056900         0.048200       0.087100
            Common Ratio (ER)                               0.484200       0.477400          0.441200         0.496700       0.505500          0.516500
            Common Cost (c}                                 0.110000       0.110000          0.110000         0.110000       0.110000          0.110000
            Total Cost of Capita! (CM}                      0.084968       0.087754          0.083753         0.084591       0.085804          0.093126

          Tax Rate (F}                                      0.035895       0.033783          0.031183         0.035609      0.034951           0.030593

          Operating Expenses
            Depreciation Factor (D}                       0.0153010       0.0271140         0.0229240        0.0277360     0.0202970          0.0197710
            Insurance Expense (I)                         0.0038030       0.0011480         0.0038520                      0.0021750          0.0018310
            Property Tax (PT)                             0.0043820       0.0082710         0.0166890        0.0121940     0.0067670          0.0074320
            Franchise Tax (FT)                            0.0001530                         0.0010110        0.0020450                        0.0008500
            Operations & Maintenance (OM)                 0.0351800       0.0374620         0.0356540        0.0424620     0.0448010          0.0263850
            Total Operating Expenses                      0.0588190       0.0739950         0.0801300        0.0844370     0.0740400          0.0562690

          Net Investment Ratio (K)                         0.517861        0.516663          0.531977         0.344901      0.447296           0.637603

          Annual Ownership Cost                            0.234443        0.264754          0.265562         0.365015      0.286282           0.211969

          Net Transmission Investment *AOC             50,367 ,215.00 69,274,300.00 38,644,785.00          3,310,937.00 44,669,649.00 30,275,883.00

          System Average Annual Ownership Cost        236,542,769.00 I           929,949,973.49              0.2543608

          System Average Monthly Ownership Cost                                       0.2543608     /12      0.0211967

          Responslbllity Ratio                                0.2104             0.2606           0.1377        O.o450         0.1808             0.1655

          Transmission Responsibility                 195,661,474.42 242,344,963.09 128,054,111.35 41,847,748.81 168,134,955.21 153,906,720.61

          Investment Difference                        19, 176,310.83 19,310,383.32 17,466,653.11 (32,777,059.96) (12,101,221.41) (11,075,065.89)

          Payments                                                                                          694,766.45    256,506.31         234,755.17

          Receipts                                       406,475.06      409,316.96        370,235.91




Attachment Snepshtt: :Z01012291)80014                             Runic: 18142                                                     Bllllng Snapshot: :Z0101:Z2B1705J9




                                                                          14
 Entergy Electric System                            Date range. 20101201 through 20101231                                                          Attachment 5
 Intra-System Billlng-201012RA                Service Schedule MSS 21 Transmission Equalization
                                                                         w                                                                                  Page 42



                                                             AR                LA              MS               NO            EGSL               ETI

          Total Investment                             415,060,255.12 506,501,649.34 273,867,644.31 26,291,850.27 350,235,178.26 225,614,138.80
          Deferred Taxes                                37,430,361.00 58,063,215.00 30,006,678.00 3,089,864.00 25,629,920.00 19,783,447.00
          Depreciation Reserve                         162,587,708.00 186,714,652.00 98,019,787.00 14, 138,861.00 167, 174,252.00 61,398,531.00
          Net Transmission Investment                  215,042, 186.12 261, 723, 782.34 145,841, 179.31 9,063,125.27 157,431,006.26 144,432, 160.80

          Cost of Capital
            Debt Ratio (DR)                                  0.476500          0.502800        0.527000         0.455600      0.491300           0.483500
            Bond Cost (i)                                    0.061600          0.067100        0.063400         0.060700      0.060900           0.075100
            Preferred Ratio (PR)                             0'.039300         0.019900        0.031800         0,047700      0.003200
            Preferred Cost (p)                               0.059900          0.075500        0.056900         0.048200      0.087100
            Common Ratio (ER)                                0.484200          0.477400        0.441200         0.496700      0.505500          0.516500
            Common Cost (c)                                  0.110000          0.110000        0.110000         0.110000      0.110000          0.110000
            Total Cost of Capital (CM)                       0.084968          0.087754        0.083753         0.084591      0.085804          0.093126

          Tax Rate (F)                                       0.035895          0.033783        0.031183         0.035609      0.034951          0.030593

          Operating Expenses
            Depreciation Factor (D)                        0.0153010          0.0271140       0.0229240        0.0277360     0.0202970         0.0197710
            Insurance Expense (I)                          0.0038030          0.0011480       0.0038520                      0.0021750         0.0018310
            Property Tax (PT)                              0.0043820          0.0082710       0,0166890        0.0121940     0.0067670         0.0074320
            Franchise Tax (FT)                             0.0001530                          0.0010110        0.0020450                       0.0008500
            Operations & Maintenance (OM)                  0.0351800         0.0374620        0.0356540        0.0424620     0.0448010         0.0263850
            Total Operating Expenses                       0.0588190         0.0739950        0.0801300        0.0844370     0.0740400         0.0562690

          Net Investment Ratio (K)                          0.518099          0.516728         0.532524         0.344712      0.449501          0.640173

          Annual Ownership Cost                             0.234391          0.264736         0.265408         0.365149      0.285470          0.211615

          Net Transmission Investment"' AOC             50,403,953.00 69,287,707.00 38, 707,416.00           3,309,391.00 44,941,829.00 30,564,012.00

          System Average Annual Ownership Cost         237,214,308.00 I            933,533,440.10        =     0.2541037

          System Average Monthly Ownership Cost                                         0.2541037     /12      0.0211753

          Responslblllty Ratio                                 0.2094              0.2598           0.1373        0.0450        0.1818             0.1667

          Transmission Responsfbil!ty                  195,481,902.36 242,531,987.74128,174,141.33 42,009,004.80 169,716,379.41 155,620,024.46

          Investment Dlffererice                        19,560,283.76 19, 191, 794.60 17,667,037.98 (32,945,879.53) (12,285,373.15) (11, 187,863.66)

          Payments                                                                                            697,639.18    260,146.57        236,906.47

          Receipts                                        414,195.05         406,392.18      374,104.99




AttachmentSnap1;hd;: 2.011D125173007                                RunlD: 18459                                                     B!Ulng Snapshot: 2()110125162604




                                                                              15
 Entergy Electric System                           Date range -20110101 through 20110131                                                          Attachment 5
 Intra-System Billing-201101RA               Service Schedule MSS • 2 /Transmission Equalization                                                       Page 42



                                                            AR               LA              MS             NO              EGSL               ET!

          Total Investment                             415,393,432.12 507 ,724,414.94   274,208,896.85 26,332, 130.65   351,726,496.11 226,605,916.47
          Deferred Taxes                                37,430,361.00 58,063,215.00      30,006,678.00 3,089,864.00      25,629,920.00 19,783,447.00
          Depreciation Reserve                         162,587,708.00 186,714,652.00    98,019,787.00 14, 138,861.00    167,174,252.00 61,398,531.00
          Net Transmission Investment                  215,375,363.12 262,946,547.94    146,182,431.85 9,103,405.65     158,922,324.11 145,423,938.47

          Cost of Capital
            Debt Ratio (DR)                                 0.476500        0.502800         0.527000       0.455600        0.491300           0.483500
            Bond Cost (i)                                   0.061600        0.067100         0.063400       0.060700        0.060900           0.075100
            Preferred Ratio (PR)                            0.039300        0.019900         0.031800       0.047700        0.003200
            Preferred Cost (p)                              0.059900        0.075500         0.056900       0,048200        0.067100
            Common Ratio (ER)                               0.464200        0.477400         0.441200       0.496700        0.505500           0.516500
            Common Cost (c)                                 0.110000        0.110000         0.110000       0.110000        0.110000           0.110000
            Total Cost of Capital (CM}                      0.064966        0.087754         0.083753       0.084591        0.065804           0.093126

          Tax Rate (F)                                      0,035695        0.033763         0.031163       0.035609        0.034951           0.030593

          Operating Expenses
            Depreciation Factor (D)                        0.0153010       0.0271140       0.0229240       0.0277360       0.0202970         0.0197710
            Insurance Expense (I)                          0.0038030       0.0011460       0.0036520                       0.0021750         0.0016310
            Property Tax (PD                               0.0043620       0.0082710       0.0166890       0.0121940       0.0067670         0.0074320
            Franchise Tax (FT)                             0.0001530                       0.0010110       0.0020450                         0.0008500
            Operations & Maintenance (OM)                  0.0351800       0.0374620       0.0356540       0.0424620       0.0448010         0.0263650
            Total Operating Expenses                       0.0566190       0.0739950       0.0601300       0;0644370       0.0740400         0.0562690

          Net Investment Ratio (K)                          0.516465        0.517892        0.533106        0.345715        0.451635           0.641748

          Annual Ownership Cost                             0.234306        0.264414        0.265243        0.364436        0.284620           0.211399

          Net Transmission Investment* AOC             50,463,740.00 69,526,749.00 36,773,667,00         3,317,627.00 45,232,472.00 30,742,475.00

          System Average Annual Ownership Cost         236,056,930.00 I       937,954,011.14         =     0.2536045

          System Average Monthly Ownership Cost                                    0.2536045      / 12     0.0211504

          Responsib!lity Ratio                                0.2101          0.2601           0.1374         O.D451          0.1604             0.1669

          Transmission Responslbllity                  197,064,137.74 243,961,836.30 126,674,681.13 42,301,725.90 169,206,903.61 156,544,524.46

          Investment Difference                        16,311,225.36 16,984, 709.64 17,307,550.72 (33,196,320.25) (10,264,579.50) (11, 120,565,99)

          Payments                                                                                        702,156.87      217,522.70        235,204.55

          Receipts                                        387,289.25      401,533.70      366,061.16




Attachment Snapshct: 2Cl11Cl223222207                              RunlD: 18694                                                    ermng Snapsht1t: 2011e12232222!l7




                                                                           16
 Entergy Electric System                           Date range -20110201 through 20110228                                                            Attachment 5
 Intra-System Billing-201102RA               Service Schedule MSS 2 /Transmission Equalizatlon
                                                                      M                                                                                  Page42



                                                            AR                 LA                MS              NO           EGSL               ETI

          Total Investment                            415,506,469.44      510,394,566.06    289,177,798.89 26,421,689.73 351,505,989.04 227,499,338.89
          Deferred Taxes                              37,430,361.00        58,063,215.00     30,006,678.00 3,089,864.00 25,629,920.00 19,783,447.00
          Depreciation Reserve                        162,587, 708.00     186, 714,652.00    98,019, 787.00 14, 138,861.00 167, 174,252.00 61,398,531.00
          Net Transmission Investment                 215,488,400.44      265,616,699.06    161,151,333.89 9, 192,964.73 158,701,817.04 146,317,360.89

          Cost of Capital
            Debt Ratio (DR)                                0.476500            0.502800          0.527000       0.455600       0.491300          0.483500
            Bond Cost (I)                                  0.061600            0.067100          0.063400       0.060700       0.060900          0.075100
            Preferred Ratio (PR)                           0.039300            0.019900          0.031800       0.047700       0.003200
            Preferred Cost (p)                             0.059900            0.075500          0.056900       0.048200       0.087100
            Common Ratio (ER)                              0.484200            0.477400          0.441200       0.496700       0.505500          0.516500
            Common Cost (c)                                0.110000            0.110000          0.110000       0.110000       0.110000          0.110000
            Total Cost of Capita! (CM)                     0.084968            0.087754          0.083753       0.084591       0.085804          0.093126

          Tax Rate (F)                                     0.035895            0.033783          0.031183       0.035609       0.034951          0.030593

          Operating Expenses
            Depreciation Factor (D)                       0.0153010          0.0271140         0.0229240       0.0277360      0.0202970        0.0197710
            Insurance Expense (I)                         0.0038030          0.0011480         0.0038520                      0.0021750        0.0018310
            Property Tax (PT)                             0.0043820          0.0082710         0.0166890       0.0121940      0.0067670        0.0074320
            Franchise Tax (FT)                            0.0001530                            0.0010110       0.0020450                       0.0008500
            Operations & Maintenance (OM)                 0.0351800          0.0374620         0.0358540       0.0424620      0.0448010        0.0263850
            Total Operating Expenses                      0.0588190          0.0739950         0.0801300       0.0844370      0.0740400        0.0562690

          Net Investment Ratio (K)                         0.518616            0.520414         0.557274        0.347933       0.451491         0.643155

          Annual Ownership Cost                            0.234278            0.263721         0.258725        0.362881       0.284744         0.211208

          Net Transmission Investment* AOC            50,484, 191.00 70,048,701.00 41,693,879.00             3,335,952.00 45, 189,390.00 30,903,397.00

          System Average Annual Ownership Cost        241,655,51 o.oo I           956,468,576,05               0.2526539

          System Average Monthly Ownership Cost                                        0.2526539      / 12     0.0210545

          Responsibility Ratio                               0.2100              0.2608            0.1376         0.0453         0.1815            0.1648

          Transmission Responslbilily                 200,858,400.97 249,447,004.63 131,610,076.06 43,328,026.50 173,599,046.55 157 ,626,021.33

          Investment Difference                       14,629,999.47 16,169,694.43 29,541,257.83 (34,135,061.77) (14,897,229.51) (11,308,660.44)

          Payments                                                                                            718,696.36     313,653.59       238,098.09

          Receipts                                       308,027.19         340,444.69        621,976.15




Attachment Snapshct: 20110328192727                               RunTD: 19029                                                       BllUng snapshot: 20110328162603




                                                                             17
 Entergy Electric System                           Date range -20110301through20110331                                                            Attachment 5
 Intra-System Billing-201103RA               Service Schedule MSS ~ 21 Transmission Equalization                                                       Page 41



                                                            AR               LA                MS               NO           EGSL               ET!

          Total Investment                             415,658,021.66 510.490,052.28 289,224,221.25 26,421,689.73 351,339,192.74 229,664,396,61
          Deferred Taxes                                37,430,361.00 58,063,215.00 30,006,678.00 3,089,864.00 25,629,920.00 19,783,447.00
          Depreciation Reserve                         162,587,708.00 186,714,652.00 98,019,787.00 14, 138,861.00 167,174,252.00 61,398,531.00
          Net Transmission Investment                  215,639,952.66 265, 712, 185.28 161,197 ,756.25 9, 192,964. 73 158,535,020. 74 148,482,418.61

          Cost of Cap!tal
             Debi Ratio (DR)                                0.476500        0.502800          0.527000         0.455600       0.491300          0.483500
             Bond Cost (i)                                  0.061600        0.067100          0.063400         0.060700       0.060900          0.075100
             Preferred Ratio (PR)                           0.039300        0.019900          0.031800         0.047700       0.003200
             Preferred Cost (p)                             0.059900        0.075500          0.056900         0.048200       0.087100
             Common Ratio (ER)                              0.484200        0.477400          0.441200         0.496700       0.505500          0.516500
             Common Cost (c)                                0.110000        0.110000          0.110000         0.110000       0.110000          0.110000
             Total Cost of Capital (CM)                     0.084968        0.087754          0.083753         0.084591       0.085804          0.093126

          Tax Rate (F)                                      0.035895        0.033783          0.031183         0.035609       0.034951         0.030593

          Opera!Jng Expenses
            Depreciation Factor (D)                        0.0153010       0.0271140         0.0229240        0.0277360      0.0202970        0.0197710
            Insurance Expense (I)                          0.0038030       0.0011480         0.0038520                       0.0021750        0.0018310
            Property Tax (PT)                              0.0043820       0.0082710         0.0166890        0.0121940      0.0067670        0.0074320
            Franchise Tax (FT)                             0.0001530                         0.0010110        0.0020450                       0.0008500
            Operations & Maintenance (OM)                  0.0351800       0.0374620         0.0356540        0.0424620      0.0448010        0.0263850
            Total Operating Expenses                       0.0588190       0.0739950         0.0801300        0,0844370      0.0740400        0.0562690

          Net Investment Ratio (K)                          0.518792        0.520504          0.557345         0.347933       0.451231         0.646519

          Annual Ownership Cost                             0.234239        0.263697          0.258706         0.362881       0.284839         0.210752

          Net Transmission Investment• AOC             50,511,287.00 70,067,506.00 41,702,827.00            3,335,952.00 45, 156,957.00 31,292,967.00

          System Average Annual Ownership Cost        242,067,496.00 I            958,760,298,27              0.2524797

          System Average Monthly Ownership Cost                                        0.2524797     / 12     0.0210400

          Responslbf!lty Ratio                                0.2088              0.2615           0.1377        0.0455         0.1809            0.1656

         Transmission Responsibility                  200, 189,150.28 250,715,818.00 132,021,293.07 43,623,593.57 173,439,737.96 158,770,705.39

          Investment Difference

          Payments
                                                       15,450,802.38 14,996,367,28 29,176,463.18 (34,430,628.84) (14,904,717.22) (10,288,286.78)

                                                                                                             724,419.52     313,594.86       216,465.28
                                                                                                                                                                      l
                                                                                                                                                                      I


          Receipts                                        325,084.47      315,523.17        613,872.01




Attachment Snapshct: 20110426164256                                Run[D: 19349                                                     BJIUng Snapshot: 20110426161055




                                                                           18
 Entergy Electric System                            Date range -20110401 through 20110430                                                         Attachment 5
 Intra-System Bllllng-201104RA               Service Schedule MSS ~ 21 Transmission Equalization                                                       Page 45



                                                            AR               LA               MS              NO            EGSL               ETI

           Tota! Investment                            415,088,642,28   512,511,972.90 290,098,703.50 26,520,278.59 353,427,619.57 232,455,038.76
           Deferred Taxes                               37,430,361.00    58,063,215.00 30,006,678.00 3,089,864.00 25,629,920.00 19,783,447.00
           Depreciation Reserve                        162,587,706.00   186,714,652.00 98,019,787.00 14, 138,861.00 167,174,252.00 61,398,531.00
           Net Transmission Investment                 215,070,573.28   267,734, 105.90 162,072,238.50 9,291,553.59 160,623,447.57 151,273,060.76

           Cost of Capital
             Debt Ratio (OR)                                0.476500        0.502800         0.527000         0.455600       0.491300          0.483500
             Bond Cost (I)                                  0.061600        0.067100         0,063400         0,060700       0,060900          0.075100
             Preferred Ratio (PR)                           0.039300        0.019900         0.031800         0.047700       0.003200
             Preferred Cost (p)                             0.059900        0.075500         0.056900         0.048200       0.087100
             Common Ratio (ER)                              0.484200        0.477400         0.441200         0.496700       0.505500          0.516500
             Common Cost (c)                                0.110000        0.110000         0.110000         0.110000       0.110000          0.110000
             Total Cost of Capital (CM)                     0.084968        0,087754         0.083753         0.084591       0.085804          0.093126

           Tax Rate (F)                                     0.035895        0.033783         0.031183         0,035609       0.034951          0.030593

           Operating Expenses
             Depreciation Factor (0)                      0.0153010        0.0271140        0.0229240        0.0277360      0.0202970        0.0197710
             Insurance Expense {I)                        0.0036030        0.0011480        0.0038520                       0.0021750        0.0018310
             Property Tax (PT)                            0.0043820        0.0082710        0.0166890        0.0121940      0.0067670        0.0074320
             Franchise Tax (FT)                           0.0001530                         0.0010110        0.0020450                       0.0006500
             Operations & Maintenance (OM)                0.0351800        0.0374620        0.0356540        0.0424620     0.0448010         0.0263850
            Total Operating Expenses                      0.0588190        0,0739950        0.0801300        0.0844370     0.0740400         0.0562690

          Net Investment Ratio (K)                         0.518132         0.522396         0.558680         0.350357       0.454473          0.650763

          Annual Ownership Cost                            0.234384         0.263182         0.258363         0.361202      0.283668           0.210185

          Net Transmission Investment* AOC             50,409,101.00 70,462,797.00 41,873,470.00           3,356, 128.00 45,563,732.00 31,795,326.00

          System Average Annual Ownership Cost        243,460,556.00 I           966,064,979.60              0.2520126

          System Average Monthly Ownership Cost                                       0.2520126     /12      0.0210010

          ResponslbllJly Ratio                               0.2071              0.2627           0.1380        0.0454         0.1811            0.1657

          Transmission Responsibility                 200,072,057.26 253,785,270.14 133,316,967.18 43,659,350.07 174,954,367.81 160,076,967.12

          Investment Difference                        14,998,516.00 13,946,635.76 26,755,271.32 (34,567,796.46) (14,330,920.24) (6,603,906.36)

          Payments                                                                                          725,960.05     300,964.38       184,891.28

          Receipts                                       314,984.60       292,940.21       603,890.91




Attai::hment Snapshct: 20110525170533                             RunlD: 19693                                                     Biiiing Snapshot: 20110625170533




                                                                           19
                                                                                                                                                                      I

 Entergy Electric System                           Date range - 20110501 through 20110531                                                         Attachment 5
                                                                                                                                                                      I
 Intra-System Billing-201105RA               Service Schedule MSS - 21 Transmission Equalization                                                       Page 42



                                                            AR               LA               MS               NO           EGSL                ETI
          Total Investment                             418,905,714.73 516,003,522.22 290,104,664.22 27,616,205.12 353,181,118. 18 235,558,750.94
          Deferred Taxes                                37,430,361.00 58,063,215.00 30,006,678.00 3,089,864.00 25,629,920.00 19,783,447.00
          Depreciation Rese!Ve                         162,587,708.00 186,714,652.00 98,019,787.00 14,138,861.00 167, 174,252.00 61,398,531.00
          Net Transmission Investment                  218,887,645.73 271,225,655.22 162,078, 199.22 10,387,480.12 160,376,946.18 154,376,772.94

          Cost of Capital
            Debt Ratio (DR)                                 0.476500        0.502800         0.527000         0.455600       0.491300          0.483500
            Bond Cost (I)                                   0.061600        0.067100         0.063400         0.060700       0.060900          0.075100
            Preferred Ratio (PR)                            0.039300        0.019900         0.031800         0.047700       0.003200
            Preferred Cost (p)                              0.059900        0.075500         0.056900         0.048200       0.087100
            Common Ratio (ER)                               0.484200        0.477400         0.441200         0.496700       0.505500          0.516500
            Common Cost (c)                                 0.110000        0.110000         0.110000         0.110000       0.110000          0.110000
            Total Cost of Capita! (CM)                      0.084968        0.087754         0.083753         0.084591       0.085804          0.093126

          Tax Rate (F)                                      0.035895        0.033783         0.031183         0.035609       0.034951          0.030593
          Operating Expenses
            Depreciation Factor (D)                       0.0153010       0.0271140         0.0229240               '
                                                                                                             0.0277360      0.0202970         0.0197710
            Insurance Expense (I}                         0.0038030       0.0011480         0.0038520                       0.0021750         0.0018310
             Property Tax (PD                             0.0043820       0.0082710         0.0166890        0.0121940      0.0067670         0.0074320
            Franchise Tax (FT)                            0.0001530                         0.0010110        0.0020450                        0.0008500
            Operations & Maintenance {OM)                 0.0351800       0.0374620         0.0356540        0,0424620      0.0448010         0.0263850
            Total Operating Expenses                      0.0588190       0.0739950         0.0801300        0.0844370      0.0740400         0.0562690

          Net Investment Ratio (K)                         0.522522         0.525628         0.558689         0.376137       0.454093          0.655364

          Annual Ownership Cost                            0.233430        0.262311          0.258361         0.344684       0.283805          0.209578

          Net Transmission Investment* AOC             51,094,943.00 71, 145,473.00 41,874,686.00          3,580,398,00 45,515, 779.00 32,353,975.00

          System Average Annual Ownership Cost        245,565,254,00 I           977,332,699.41              0.2512606

          System Average Monthly Ownership Cost                                       0.2512606     / 12     0.0209384

          Responslb!lfty Ratio                                0.2058             0.2627           0.1385        0.0457         0.1804            0.1669

         Transmission Responsiblllty                  201,135,069.54 256,745,300.14135,360,578.87 44,664,104.36 176,310,818.97 163,116,827.53

         Investment Difference                         17,752,576.19 14,480,355.08 26,717,620.35 (34,276,624.24) (15,933,872.79) (8,740,054.59)

         Payments                                                                                           717,697.25     333,629.61       183,002.65

         Receipts                                        371,710.33      303, 195.29       559,423.90




At1achmcntSnapshd:: 20110627175012                                RunlO: 20095                                                     Bllllng Snapshot: 20110627175012




                                                                          20
 Entergy Electric System                             Date range -20110601 through 20110630                                                         Attachment 5
 Intra-System Billlng-201106RA                 Service Schedule MSS - 2 /Transmission Equalization                                                      Page 41



                                                              AR              LA                MS              NO            EGSL               ET!

             Total Investment                            424,209,890.60 517,832,426.21 298,253,065.58 27,638,800.89 372,099,963.16 236,387,445.08
             Deferred Taxes                              40,474, 156.00 66,697,341.00 34,898,123.00 2,321, 112.00 28,441,593.00 23,459,553.00
             Depreciation Reserve                        168,087,392.00 206, 102,378.00 106, 141,224.00 11,539,821.00 173,877 ,578.00 68,979,950.00
             Net Transmlss!on Investment                 215,648,342.60 245,032,707.21157,213,718.58 13,777,867.89 169,780,792.16 143,947,942.08

             Cost of Capltat
               Debt Ratio (DR)                                0.474200       0.474400          0.508300         0.431500       0.474500         0.500000
               Bond Cost (I)                                  0.056200       0.064700          0.062000         0.062200       0.058300         0.069800
               Preferred Ratio (PR)                           0.039700       0.019200          0.031500         0.053800       0.003200
               Preferred Cost (p)                             0.059900       0.075300          0.056900         0.048200       0.087100
               Common Ratio (ER)                              0.486200       0,506300          0.460200         0.514700       0.522300         0.500000
               Common Cost (c)                                0.110000       0.110000          0.110000         0.110000       0.110000         0.110000
               Total Cost of Capita[ (CM)                     0.082510       0.087833          0.083929         0.086049       0.085395         0.089900

             Tax Rate (F)                                     0.036053       0.035736          0.032467         0.037031       0.036106         0.029615

             Operating Expenses
               Depreciation Factor {D)                      0.0152270       0.0283830         0.0229140        0.0292210      0.0201180        0.0205130
               Insurance Expense {I)                        0.0036370       0.0003100         0.0039710                       0.0021970        0.0017570
               Property Tax (PD                             0.0043900       0.0098690         0.0168800        0.0138350      0.0072620        0.0077650
               Franchise Tax (FT)                           0.0001400                         0.0010400        0.0018540                       0.0001760
               Operations & Maintenance (OM)                0.0372880       0.0438560         0.0365650        0.0588120      0.0435820        0.0288180
              Total Operating Expenses                      0.0606820       0.0824180         0.0813700        0.1037220      0.0731590        0.0590290

         Net Investment Ratio (K)                            0,508353        0.473189          0.527115         0.498497       0.456277         0.608949

         Annual Ownership Cost                               0.237932        0.297744          0.270764         0.331149       0.281840         0.216450

         Net Transmission Investment* AOC                51,309,641.00 72,957,018.00 42,567 ,815.00          4,562,527 .00 47,851,018.00 31,157,532.00

         System Average Annual Ownership Cost           250,405,551.00 I           945,401,370.52              0.2648669

         System Average Monthly Ownership Cost                                          0.2648669     / 12     0.0220722

         Responslbll!ty Ratio                                   0.2044             0.2626           0.1392        0.0457         0.1796            0.1685

         Transmission Responslblllty                    193,240,040.13 248,262,399.90 131,599,870.78 43,204,842.63 169,794,086.15"159,300, 130.93

         Investment Difference                           22,408,302.47   (3,229,692.69) 25,613,847.80 (29,426,974.74)        (13,293.99) (15,352, 188.85)

         Payments                                                           71,286.56                         649,519.35         293.43       338,857.25

         Receipts                                          494,601.51                        565,355.09




Atta~hment   Snapshtt:: 20110726141150                              RunlO: 20433                                                     Bltnng Snapshot: 20110725133622




                                                                           21
 Entergy Electric System                            Date range - 20110701 through 20110731                                                          Attachment 6
 Intra-System Billing-201107RA                Service Schedule MSS - 21 Transmission Equalization                                                        Page 42



                                                             AR              LA                MS                NO           EGSL               ETI

          Total Investment                              424,795,416.73 518,659,046.34 313,547,024.61 27,618,517.54 374,379,933.08 236,535,467.35
          Deferred Taxes                                40,474, 156.00 66,697,341.00 34,896,123.00 2,321, 112.00 26,441,593.00 23,459,553.00
          Depreciation Reserve                          166,067,392.00 206,102,376.00106,141,224.00 11,539,821.00 173,877,578.00 68,979,950.00
          Net Transmission Investment                   216,233,868.73 245,859,327.34 172,507,677.61 13,757 ,584.54 172,060,762.08 144,095,964.35

          Cost of Capital
            Debt Ratio (DR)                                  0.474200       0.474400           0.506300         0.431500       0.474500          0.500000
            Bond Cost (I)                                    0.056200       0,064700           0.062000         0.062200       0.056300          0.069800
            Preferred Ratio (PR)                             0.039700       0.019200           0.031500         0.053800       0.003200
            Preferred Cost (p)                               0.059900       0.075300           0.056900         0.048200       0,087100
            Common Ratio (ER)                                0.466200       0.506300           0.460200         0.514700       0.522300          0.500000
            Common Cost (c)                                  0.110000       0.110000           0.110000         0.110000       0.110000          0.110000
            Total Cost of Capital (CM)                       0.082510       0.087833           0.083929         0.086049       0.085395          0.089900

          Tax Rate (F)                                       0.036053       0.035736           0.032467         0.037031       0.036106          0.029615

          Operating Expenses
            Depredation Factor (D)                         0.0152270       0.0263830          0.0229140        0.0292210      0.0201160        0.0205130
            Insurance Expense (1)                          0.0036370       0.0003100          0.0039710                       0.0021970        0.00l7570
            Property Tax (PT)                              0.0043900       0.0098690          0.0166800        0.0136350      0.0072620        0.0077650
            Franchise Tax (FT)                             0.0001400                          0.0010400        0,0018540                       0.0001760
            Operations & Maintenance (OM)                  0.0372880       0,0438560          0.0365650        0.0588120      0.0435820        0.0288180
           Total Operating Expenses                        0.0606820       0.0824180          0.0613700        0.1037220      0.0731590        0.0590290

          Net Investment Ratio (K)                          0,509031        0.474029           0.550181         0.498129       0.459569          0.609194

          Annual Ownership Cost                             0.237773        0.297435           0.264292         0.331303       0.280664          0.216411

          Net Transmission Investment* AOC              51,414,576.00 73,127,169.00 45,592,399.00            4,557,929.00 46,294,703.00 31, 163,952.00

          System Average Annual Ownership Cost         254,170,728.00 I           964,515, 164.65              0.2635218

          System Average tvlonthly Ownership Cost                                      0.2635218      /12      0.0219602

          Responslb!llty Ratio                                 0.2031             0.2637            0.1389        0.0459         0.1795            0.1669

          Transmission Responslblflty                  195,893,034.00 254,342,654.19 133,971, 159.15 44,271,246.98 173,130,475.64 162,906,614.69

          Investment Difference                         20,340,834.73   (8,463,326.85) 36,536,518.46 (30,513,662.44) (1,069,713.56) (18,810,650.34)

          Payments                                                        186,295.09                          670,084.47      23,491.07       413,084,62

          Receipts                                        446,687.69                         846,267.56




Attachment Snapshct: 20110828185123                                RunlD: 20828                                                      Bllllng Snapshot: 20110826165123




                                                                           22
  Entergy Electric System                           Date range -20110801 through 20110831                                                          Attachment 5
  Intra-System Billing-20110BRA              Service Schedule MSS 2 /Transmission Equalization
                                                                      R                                                                                 Page 41



                                                           AR                  LA              MS               NO           EGSL                ETI

          Total Investment                            430,480,300.58 519,579,413.16       313,695,696.12 27,619, 102.03 375,686,576.07 236,733,346.30
          Deferred Taxes                               40,474, 156.00 66,697,341.00        34,696, 123.00 2,321, 112.00 26,441,593.00 23,459,553.00
          Depreciation Reserve                        166,087,392.00 206,102,376.00       106,141.224.00 11,539,621.00 173,677,576.00 66,979,950.00
          Net Transmission Investment                 221,916,752.56 246,779,694.16       172,656,549.12 13,756,169.03 173,567,405.07 144,293,645.30

          Cost of Capital
            Debt Ratio (DR)                                0.474200           0.474400        0.506300         0.431500       0.474500          0.500000
            Bond Cost (i)                                  0.056200           0.064700        0.062000         0.062200       0.056300          0.069800
            Preferred Ratio (PR)                           0.039700           0.019200        0.031500         0.053600       0.003200
            Preferred Cost (p}                             0.059900           0.075300        0.056900         0.048200       0,067100
            Common Ratio {ER)                              0.466200           0.506300        0.460200         0,514700       0.522300          0.500000
            Common Cost (c)                                0.110000           0.110000        0.110000         0.110000       0.110000          0.110000
            Total Cost of Capltal {CM)                     0.062510           0.087833        0.063929         0.066049       0.065395          0.089900

          Tax Rate (F)                                     0.036053           0.035736        0.032467         0.037031       0.036106          0.029615

          Operating Expenses
            Depreciation Factor (D)                       0.0152270          0.0263630       0.0229140        0.0292210     0.0201160         0.0205130
            Insurance Expense (I)                         0.0036370          0.0003100       0.0039710                      0.0021970         0.0017570
             Property Tax (PT)                            0.0043900          0.0096690       0.0168800        0.0138350     0.0072620         0.0077650
            Franchise Tax (FT)                            0.0001400                          0.0010400        0.0016540                       0.0001760
            Operations & Maintenance (OM)                 0.0372660          0.0436560       0.0365650        0.0566120     0.0435820         0.0288180
            Total Operating Expenses                      0.0606620          0.0824160       0.0613700        0.1037220     0.0731590         0.0590290

          Net Investment Ratio (K)                         0.515514           0.474960        0.550661         0.496140       0.461755          0.609521

          Annual Ownership Cost                            0.236274           0.297095        0.264156         0.331296       0.279937          0.216359

          Net Transmission Investment* AOC            52,433,631.00 73,317,013.00 45,661,440.00             4,558,054.00 46,567,939.00 31,219,272.00

          System Average Annual Ownership Cost        255,777,349.00 I           973, 174,415.26              0.2626279

          System Average Monthly Ownership Cost                                       0.2626279      /12      0.0219023

          ResponslbJllly Ratio                               0.2043              0.2630            0.1389        0.0456         0.1792             0.1690

         Transmission Respons!bllity                  196,619,533.04 255,944,671.21135,173,926.26 44,376,753.34 174,392,855.21164,466,476.16

          Investment Difference                       23,099.219.54       (9,165,177.05) 37,662,622.64 (30,616,564.31)     (625,450.14) (20, 172,630.68)

          Payments                                                          200,736.66                       670,618.08      16,079.27       441,827.45

          Receipts                                       505,926.54                         825,336.93




Attachmen(Snapshct: 20110927172811                               RunlD: 21193                                                       Blll!ng Snapshot: 20110921164044




                                                                            23
 Entergy Electric System                           Date range -20110901through20110930                                                             Attachment 5
 Intra-System Bllling-201109RA               Service Schedule MS~ - 21 Transmission Equalization                                                        Page 40



                                                            AR              LA                MS               NO           EGSL                ETI
          Total Investment                             434,281,095.23 519,752,682.65 314,109,029.61 27,619,102.03 377,406,576.04 236,757,056.43
          Deferred Taxes                                40,474, 156.00 66,697,341.00 34,898, 123.00 2,321,112.00 28,441,593,00 23,459,553.00
          Depreciation Reserve                         168,087,392.00 206,102,378.00 106,141,224.00 11,539,821.00 173,677,578.00 66,979,950.00
          Net Transmission Investment                  225,719,547.23 246,952,963.65173,069,662.61 13,758,169.03 175,087,405.04144,317,553.43

          Cost of Capita!
            Debt Ratio (DR)                                 0.474200        0.474400         0.508300         0.431500       0.474500           0.500000
            Bond Cost (i)                                   0.056200        0.064700         0.062000         0.062200       0.058300           0.069800
            Preferred Ratio (PR)                            0.039700        0.019200         0.031500         0.053800       0.003200
            Preferred Cost (p)                              0.059900        0.075300         0,056900         0.048200       0.087100
            Common Ratlo (ER)                               0.486200        0.506300         0.460200         0.514700       0.522300           0.500000
            Common Cost (c)                                 0.110000        0.110000         0.110000         0.110000       0.110000           0.110000
            Total Cost of Capital (CM)                      0.082510        0.087833         0.083929         0.086049       0.085395           0.089900

          Tax Rate (F)                                      0.036053        0.035736         0.032467         0.037031       0.036106           0.029615

          Operating Expenses
            Depreciation Factor (D)                       0.0152270       0.0283830         0.0229140        0.0292210     0.0201180          0.0205130
            Insurance Expense {J)                         0.0036370       0.0003100         0.0039710                      0.0021970          0.0017570
            Property Tax (PT)                             0.0043900       0.0098690         0.0168800        0.0138350     0.0072620          0.0077650
            Franchise Tax (FT)                            0.0001400                         0.0010400        0.0018540                        0.0001760
            Operations & Maintenance (OM)                 0.0372880       0.0438560         0.0365650        0.0588120     0.0435820          0.0288180
            Total Operating Expenses                      0.0606820       0.0824180         0.0813700        0.1037220     0.0731590          0.0590290

          Net Investment Ratlo (K)                         0.519754        0.475136          0.550986         0.498140      0.463923           0.609560

          Annual Ownership Cost                            0.235314        0.297030          0.264076         0.331298      0.279197           0.216353

          Net Transmission Investment *AOC             53, 114,970.00 73,352,439.00 45,703,550,00          4,558,054.00 48,883,878.00 31,223,536.00

          System Average Annual Ownership Cost        256,836,427.00 I           978,905,320.99              0.2623711

         System Average Monthly Ownership Cost                                        0.2623711     / 12     0.0218643

         Responsibility Ratio                                0.2054              0.2636           0.1384        0.0454        0.1781              0.1691

         Transmission Responsibil!ty                  201,067, 152.93 258,039,442.61 135,480,496.43 44,442,301.57 174,343,037.67 165,532,889.78

         Investment Difference                         24,652,394.30 (11,086,478.96) 37,589,186.18 (30,684,132.54)        744,367.37 (21,215,336.35)

         Payments                                                        242,397.60                         670,885.70                       463,857.52

         Receipts                                        539,006.24                        821,859.55                       16,275.04




AttachmentSnapshot: 20111026161442                                RunlD: 21466                                                     Blll!ng Snapshot: 2111111126161442




                                                                          24
 Entergy Electric System                              Date range-20111001through20111031                                                             Attachment 5
 Intra-System Billing-20111 ORA                Service Schedule MSS ~ 21 Transmission Equalization                                                        Page 37



                                                              AR               LA                MS               NO           EGSL               ETI

          Total Investment                               435,044,558.90 520,322,159.84315,132,168.58 27,616,290.90 381,121,510.02 236,812,347.39
          Deferred Taxes                                  40,474,156.00 66,697,341.00 34,898,123.00 2,321,112.00 28,441,593.00 23,459,553.00
          Depreciation Reserve                           168,087,392.00 206,102,378.00 106, 141,224.00 11,539,821.00 173,877,578.00 68,979,950.00
          Net Transmission Investment                    226,483,010.90 247,522,440.84174,092,621.58 13,755,357.90 178,802,339.02 144,372,844.39

          Cost of Capltal
            Debt Ratio (DR)                                   0.474200        0.474400          0.508300         0.431500       0.474500          0.500000
            Bond Cost (J)                                     0.056200        0.064700          0.062000         0.062200       0.058300          0.069800
            Preferred Ratio (PR)                              0.039700        0.019200          0.031500         0.053800       0.003200
            Preferred Cost {p)                                0.059900        0.075300          0.056900         0.048200       0.087100
            Common Ratio (ER)                                 0.486200        0.506300          0.460200         0.514700       0.522300          0.500000
            Common Cost {c)                                   0.110000        0.110000          0.110000         0.110000       0.110000          0.110000
            Total Cost of Capital (CM)                        0.082510        0.087833          0.083929         0.086049       0.085395          0.089900

          Tax Rate (F)                                        0.036053        0,035736          0.032467         0.037031       0.036106          0.029615

          Operating Expenses
            Depreciation Factor (D)                         0.0152270        0.0283830         0.0229140        0.0292210      0.0201180        0.0205130
            Insurance Expense (I)                           0.0036370        0.0003100         0,0039710                       0.0021970        0.0017570
            Property Tax (PT)                               0.0043900        0.0098690         0.0168800        0.0138350      0.0072620        0.0077650
            Franchise Tax {FT)                              0.0001400                          0.0010400        0.0018540                       0.0001760
            Operations & Maintenance (OM)                   0.0372880        0.0438560         0.0365650        0.0588120     0.0435820         0.0288180
            Total Operating Expenses                        0.0606820        0.0824180         0.0813700        0,1037220     0.0731590         0.0590290

          Net Investment Ratio (K)                            0.520597        0.475710          0.552444         0.498089      0.469148           0.609651

          Annual Ownership Cost                               0.235125        0.296821          0.263686         0.331319      0.277441           0.216339

          Net Transmission Investment "' AOC             53,251,818.00 73,469,858.00 45,905,840.00            4,557,411.00 49,607' 100.00 31,233,477.00

          System Average Annual Ownership Cost          258,025,504,00 I            985,028,814.63              0.2619472

          System Average Monthly Ownership Cost                                          0.2619472     / 12     0.0218289

          Responsibility Ratio                                  0.2072              0.2618           0.1390        0.0448         0.1769            0.1703

         Transmission Responsibility                    204,097,970,39 257,880,543.67 136,919,005.23 44, 129,290.90 174,251,597.31 167,750,407.13

          Investment Difference                          22,385,040.51 (10,358,102.83) 37, 173,816.35 (30,373,933.00)       4,550,741.71 (23,377,562.74)

         Payments                                                           226,106.30                         663,030.47                      610,307.19

         Receipts                                          488,641.49                         811,464.65                       99,337.82




Attachment Snapshct: 20111122172545                                  RunlD: 21756                                                     Biiiing Snapshot: 20111122170808




                                                                             25
 Entergy Electric System                            Date range -20111101through20111130                                                           Attachment 5
 Intra-System Bllllng-201111RA               Service Schedule MSS ~ 2 /Transmission Equalization                                                       Page 37



                                                            AR              LA                MS              NO            EGSL               ETI

          Total Investment                             457,964,979.45 510,584,691.68 314,533,166.34 27,617, 140.62 381,298,924.42 236,909,330.02
          Deferred Taxes                               40,474,156.00 66,697,341.00 34,898, 123.00 2,321, 112.00 28,441,593.00 23,459,553.00
          Depreciation Reserve                         168,087,392.00206,102,378.00 106,141,224.00 11,539,821.00 173,877,578.00 68,979,950.00
          Net Transmission Investment                  249,403,431.45 237,784,972.68 173,493,819.34 13,756,207.62 178,979,753.42 144,469,827.02

          Cost of Capital
            Debt Ratio (DR)                                 0.474200       0.474400          0.508300         0.431500       0.474500          0.500000
            Bond Cost (I)                                   0.056200       0.064700          0.062000         0.062200       0,058300          0.069800
            Preferred Ratio (PR)                            0.039700       0.019200          0.031500         0.053800       0.003200
            Preferred Cost (p)                              0.059900       0.075300          0.056900         0.048200       0.087100
            Common Ratio {ER)                               0.486200       0.506300          0.460200         0.514700       0.522300          0.500000
            Common Cost (c)                                 0.110000       0.110000          0.1.10000        0.110000       0.110000          0.110000
            Total Cost of Capital (CM)                      0.082510       0.087833          0.083929         0.086049       0.085395          0.089900

          Tax Rate (F)                                      0.036053       0.035736          0.032467         0.037031       0.036106          0.029615

          Operating Expenses
            Depreciation Factor (D)                       0.0152270       0.0283830         0.0229140        0.0292210     0.0201180         0.0205130
            Insurance Expense (I)                         0.0036370       0.0003100         0.0039710                      0.0021970         0.0017570
            Property Tax (PT)                             0.0043900       0.0098690         0.0168800        0.0138350     0.0072620         0.0077650
            Franchise Tax (FT)                            0.0001400                         0.0010400        0.0018540                       0.0001760
            Operations & Maintenance (OM)                 0.0372880       0.0438560         0.0365650        0.0588120     0.0435820         0.0288180
           Total Operating Expenses                       0.0606820       0.0824180         0.0813700        0.1037220     0.0731590         0.0590290

         Net Investment Ratio (K)                          0.544591        0.465711          0.551591         0.498104      0.469395           0.609811

         Annual Ownership Cost                             0.229989        0.300541          0.263914         0.331313      0.277359           0.216313

         Net Transmission Investment • AOC             57,360,046.00 71,464, 133.00 45,787,448.00          4,557,610.00 49,641,645.00 31,250,702.00

         System Average Annual Ownership Cost         260,061,584.00 I           997,888,011.53              0.2606120

         System Average Monthly Ownership Cost                                        0.2606120     / 12     0.0217177

         Responsibility Ratio                                 0.2100             0.2617           0.1394        0.0446         0.1755            0.1688

         Transmission Responsibllity                  209,556,482.42 261,147,292.62 139,105,588.81 44,505,805.31 175,129,346.02 168,443,496.35

         Investment Difference                         39,846,949.03 (23,362,319.94) 34,388,230.53 (30,749,597.69)       3,850,407.40 (23,973,669.33)

         Payments                                                        507,375.06                         667,809.50                      520,652.15

         Receipts                                        865,382.74                        746,832.11                       83,621.86




AttachmentSnapshct: 20111227164353                                RunlD: 22082                                                     Biiiing Snapshot: 2011122T112163




                                                                          26
 Entergy Electric System                            Date range· 20111201 through 20111231                                                       Attachment 5
 Intra-System Billlng-201112RA                Service Schedule MSS • 2 /Transmission Equalization                                                    Page 41



                                                             AR              LA            MS               NO            EGSL               ETI

          Total Investment                              457,923, 799.10 553,067,455.46 315, 119,324.43 27,811,915.33 382,387,047.05 237,338,942.04
          Deferred Taxes                                41,509,084.00 66,689,174.00 34,950, 141.00 2,321, 112.00 28,927, 199.00 23,457, 174.00
          Depreciation Reserve                          170,463, 164.00 212,366,961.00 107,272,787.00 13,895,838.00 185,508,528.00 72, 198,072.00
          Net Transmission Investment                   245,951,551.10 274,011,320.46 172,896,396.43 11,594,965.33 167,951,320.05 141,683,696.04

          Cost of Capital
            Debt Ratio (DR)                                  0.474200       0.474400       0.508300        0.431500       0.474500           0.500000
            Bond Cost (!)                                    0.056200       0.064700       0.062000        0.062200       0.058300           0.069800
            Preferred Ratio {PR)                             0.039700       0.019200       0.031500        0.053800       0.003200
            Preferred Cost {p)                               0.059900       0.075300       0.056900        0.048200       0.087100
            Common Ratio (ER)                                0.486200       0.506300       0.460200        0.514700       0.522300           0.500000
            Common Cost (c)                                  0.110000       0.110000       0.110000        0.110000       0.110000           0.110000
            Total Cost of Capita! (CM)                       0.082510       0.087833       0.083929        0.086049       0.085395           0.089900

          Tax Rate {F)                                       0.036053       0.035736       0.032467        0.037031       0.036106           0.029615

          Operating Expenses
            Depreclatlon,Factor (D)                         0.0179350      0.0282680      0.0229150       0.0292230      0.0200840         0.0199850
            Insurance Expense (I)                           0.0036430      0.0003100      0.0039710                      0.0022010         0.0017570
            Property Tax (PT)                               0.0043920      0.0098170      0.0168800       0.0129480      0.0072380         0.0077710
            Franchise Tax (FT)                              0.0001400                     0.0010400       0.0018540                        0.0001760
            Operations & Maintenance (OM)                   0.0372840      0.0438560      0.0365640       0.0588120      0.0435800         0.0288180
            Total Operating Expenses                        0.0633940      0.0822510      0.0813700       0.1028370      0.0731030         0.0585070

          Net Investment Ratio (K)                           0.537101       0.495439       0.548670        0.416906       0.439218           0.596968

          Annual Ownership Cost                              0.236592       0.289585       0.264700        0.369747       0.287939           0.217521

          Net Transmission Investment " AOC             58, 190, 169.00 79,349,568.00 45,765,676.00     4,287,204.00 48,359, 735.00 30,619, 179.00

          System Average Annual Ownership Cost          266,771,531.00              1,014,089,249.41      0.2630651

         System Average Monthly Ownership Cost                                     0.2630651     / 12     0.0219221

          Responslblllty Ratio                                 0.2099         0.2636           0.1393        0.0449         0.1745             0.1678

         Transmission Responsib!lity                   212,857,333.45 267,313,926.14141,262,632.44 45,532,607.30 176,958,574.02 170, 164, 176.05

         Investment Difference                          33,094,217.65    6,697,394.32 31,633,763.99 (33,937,641.97) (9,007,253.97)(28,480,480.01)

         Payments                                                                                        743,984.21     197,457.88        624,351.79

         Receipts                                          725,494.58     146,820.91     693,478.38




AttachmentSnapshc:t: 20120126166421                                RunlD: 22492                                                  Bllllng Snapshot: 20120126166421




                                                                           27
 Entergy Electric System                           Date range- 20120101through20120131                                                             Attachment 5
 Intra-System Billing-201201RA               Seivlce Schedule MSS - 21 Transmission Equalization                                                        Page 37



                                                            AR               LA               MS                 NO           EGSL               ETI

         Total Investment                              459,376,596.35 578,023,878.86 315,198,832.13 27,838,490.60 406,901,848.55 249,029,020.71
         Deferred Taxes                                41,509,083.72 66,689,174.20 34,950, 140.83 2,321, 111.83 28,927, 199.09 23,457, 174.17
         Depreciation Reserve                          170,463, 164.00 212,366,961.00 107,272,787.00 13,895,838.00 185,508,528.00 72, 198,072.00
         Net Transmission Investment                   247,404,348.63 298,967,743.66 172,975,904.30 11,621,540.77 192,466,121.48 153,373,774.54

         Cost of Capital
           Debt Ratio {DR)                                  0.474200        0.474400          0.508300          0.431500       0.474500         0.500000
            Bond Cost 0)                                    0.056200        0.064700          0.062000          0.062200       0.058300         0.069800
            Preferred Ratio (PR}                            0.039700        0.019200          0.031500          0.053800       0.003200
            Preferred Cost (p)                              0.059900        0.075300          0.056900          0.048200       0.087100
            Common Ratio (ER)                               0.486200        0.506300          0.460200          0.514700       0.522300         0.500000
            Common Cost (c)                                 0.110000        0.110000          0.110000          0.110000       0.110000         0.110000
            Total Cost of Capital (CM)                      0.082510        0.087833          0.083929          0.086049       0.085395         0.089900

         Tax Rate (F)                                       0.036053        0.035736          0.032467          0.037031       0.036108         0.029615

         Operating Expenses
            Depreciation Factor (D)                        0,0179352       0.0282677         0.0229146         0.0292235      0.0200843        0.0199853
            Jnsurarice Expense (J)                         0.0036433       0.0003102         0.0039709                        0.0022009        0.0017573
            Property Tax (PT)                              0.0043916       0.0098170         0.0168802         0.0129483      0.0072383        0.0077706
            Franchise Tax (FT)                             0.0001400                         0.0010403         0.0018543                       0.0001763
            Operations & Maintenance (OM)                  0.0372840       0.0438563         0.0365643         0.0588118      0.0435803        0.0288184
            Total Operating Expenses                       0.0633941       0.0822512         0.0813703         0.1028379      0.0731038        0.0585079

         Net Investment Ratio (K)                           0.538565        0.517224          0.548783          0.417463       0.473004         0.615887

         Annual Ownership Cost                              0.236272        0.282593         0.264670           0.369420       0.276053         0.214512

         Net Transmission Investment,. AOC             58,454,720.00 84,486,192.00 45,781,533.00             4,293,230.00 53, 130,850.00 32,900,515.00

         System Average Annual O.Vnership Cost         279,047,040.00                  1,076,809,433.36        0.2591424

         System Average Monthly Ownership Cost                                         0.2591424     / 12      0.0215952

         Responsib!Jlty Ratio                                 0.2104              0.2641           0.1390         0,0448         0.1736            0.1681

         Transmission Responsibillty                  226,560,704.78 284,385,371.35 149,676,511.24 48,241,062.61 186,934, 117.63 181,011,665.75

         Investment Difference                         20,843,643.85 14,582,372.31 23,299,393.06 (36,619,521.84)           5,532,003.83 (27,637,891.21)

         Payments                                                                                             790,806.06                      596,845.91

         Receipts                                         450, 122.75     314,909,31        503,155.16                       119,464.75




AttachmentSn~pshot: 20120224111442                                 RunlO: 22947                                                      SIUlng Snapshot: 20120224111442

                          39896                                                                             CITIES 5-1ADDENDUM2 KH1626


                                                                           28
'!.,   c-


  Entergy Electric System                            Date range- 20120201 through 20120229                                                            Attachment 5
  Intra-System Bllling-201202RA                Setvlce Schedule MSS - 21 Transmission Equalization                                                         Page 37



                                                              AR                 LA                MS              NO           EGSL                ET/

            Total Investment                             460,071,953.17 577,667,972.08        332,961,761.29 32,031,480.30 406,917,788.37 248,907,519.55
            Deferred Taxes                                41,509,083.72 66,689,174.20          34,950, 140.83 2,321, 111.83 28,927, 199.09 23,457,174.17
            Depreciation Reserve                         170,463, 164.00 212,366,961.00       107,272,787.00 13,895,838.00 185,508,528.00 72,198,072.00
            Net Transmission Investment                  248,099,705.45 298,611,836.88        190,738,833.46 15,814,530.47 192,482,061.28 153,252,273.38

            Cost of Capital
              Debt Ratio (DR)                                 0.474200          0.474400          0.508300        0.431500       0.474500          0.500000
              Bond Cost 0)                                    0.056200          0.064700          0.062000        0.062200       0.058300          0.069800
              Preferred Ratio (PR)                            0.039700          0.019200          0.031500        0.053800       0.003200
              Preferred Cost (p)                              0.059900          0.075300          0.056900        0.048200       0.087100
              Common Ratio (ER)                               0.486200          0.506300          0.460200        0.514700       0.522300          0.500000
              Common Cost (c)                                 0.110000          0.110000          0.110000        0.110000       0.110000          0.110000
              Total Cost of Capita! (CM)                      0.082510          0.087833          0.083929        0.086049       0.085395          0.089900

            Tax Rate (F)                                      0.036053          0.035736          0.032467        0,037031       0.036106          0.029615

            Operating Expenses
              Depreciation Factor (D)                       0.0179352         0.0282677          0.0229146       0.0292235      0.0200843         0.0199853
              Insurance Expense (I)                         0.0036433         0.0003102          0.0039709                      0.0022009         0.0017573
              Property Tax (PT)                             0.0043916         0.0098170          0.0168802       0.0129483      0.0072383         0.0077706
              Franchise Tax (FT)                            0.0001400                            0.0010403       0.0018543                        0.0001763
              Operations & Maintenance (OM)                 0.0372840         0.0438563          0.0365643       0.0588118      0.0435803         0.0288184
              Total Operating Expenses                      0.0633941         0.0822512          0.0813703       0.1028379      0.0731038         0.0585079

            Net Investment Ratio (K)                         0.539263          0.516926           0.572855        0.493718       0.473024          0.615700

            Annual Ownership Cost                            0.236119          0.282685           0.258439        0.331372       0.276046          0.214541

            Net Transmission Investment* AOC             58,581,054.00 84,413,087.00 49,294,353.00             5,240,493.00 53, 133,903.00 32,878,896.00

            System Average Annual ownership Cost        283,541, 786.00                   1,098,999,240.92       0.2580000

            System Average Monthly Ownership Cost                                         0.2580000     /12      0.0215000

            Responsibility Raflo                                0.2104               0.2644         0.1389          0.0446         0.1727             0.1690

            Transmission Responsibility                 231,229,440.29 290,575,399.30 152,650,994.56 49,015,366.14 189,797, 168.91 185,730,871.72

            Investment Difference                        16,870,265.16    8,036,437.58 38,087,838.90 (33,200,835.67)         2,684,892.37 (32,478,598.34)

            Payments                                                                                            713,817.92                      698,289.82

            Receipts                                       362.710.68        172,783.40         818,888.48                      57,725.18




AttachmentSnapshot:    2G120325074717                               Runro:   23533                                                     Blllfng snapshot: 20120327102661
                             39896                                                                            CITIES 5-1 ADDENDUM 2 KR! 681


                                                                               29
                                     SOAH Docket No. XXX-XX-XXXX
                                             PUC Docket No. 39896
                                               ETI 2011 Rate Case
                                                ETI EXHIBIT NO. 4
                            DOCKET NO. 39896


     APPLICATION OF ENTERGY            §   PUBLIC UTILITY COMMISSION
     TEXAS, INC. FOR AUTHORITY         §
     TO CHANGE RATES AND               §          OF TEXAS
     RECONCILE FUEL COSTS              §




                           DIRECT TESTIMONY


                                     OF


                            JOSEPH F. DOMINO


                                 ON BEHALF OF


                          ENTERGY TEXAS, INC.




                             NOVEMBER 2011




2011 ETI Rate Case                                     3-1
                                ENTERGY TEXAS, INC.
                       DIRECT TESTIMONY OF JOSEPH F. DOMINO
                                  2011 RATE CASE


                                     TABLE OF CONTENTS

                                                                                  Page

     I.      Introduction                                                            1 

     II.     Purpose of Testimony                                                    3 

     III.    Overview of Filing                                                      5 

             A.  Reason for Filing                                                   5 

             B.  Summary of the Filing                                               8 

             C.  The Company’s Anticipated Future Expenditures                       9 

     IV.     Case Presentation and List of Witnesses                                11 

     V.      The Utility and Executive Management Class of Affiliate Costs          18 

     VI.     Conclusion                                                             38 



                                           EXHIBITS

     Exhibit JFD-1          Witnesses and Testimony Content

     Exhibit JFD-A          Affiliate Billings by Witness, Class and Department

     Exhibit JFD-B          Affiliate Billings by Witness, Class and Project

     Exhibit JFD-C          Affiliate Billings by Witness, Class, Department
                            and Project

     Exhibit JFD-D          Affiliate Billings Pro Forma Summary by Witness
                            and Class




2011 ETI Rate Case                                                        3-2
     Entergy Texas, Inc.                                                                Page 1 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


1                                      I.      INTRODUCTION

2    Q.      PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.

3    A.      My name is Joseph F. Domino. My business address is 350 Pine Street,

4            Beaumont, Texas.

5

6    Q.      BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY?

7    A.      I am employed by Entergy Texas, Inc. (“ETI” or the “Company”) as

8            President and Chief Executive Officer.             ETI is an integrated investor-

9            owned electric utility that provides bundled generation, transmission,

10           distribution, and customer services to approximately 412,000 retail

11           customers in Texas. ETI is a subsidiary of Entergy Corporation (“Entergy

12           Corp.”), which also owns, among other subsidiaries, Entergy Gulf States

13           Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy New Orleans, Inc.,

14           Entergy Arkansas, Inc., and Entergy Mississippi, Inc. (along with ETI, the

15           “Operating Companies”).1 Schedule F of the rate filing package describes

16           the Company in more detail.




     1
          In the remainder of this testimony, I will use the term “Entergy Companies” to mean Entergy
          Corp. and its subsidiaries, including ETI, Entergy Services, Inc. (“ESI”), and the other
          Operating Companies. Each of these subsidiaries is a separate legal entity.




2011 ETI Rate Case                                                               3-3
     Entergy Texas, Inc.                                                         Page 2 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


1    Q.      PLEASE       BRIEFLY       DESCRIBE        YOUR       EDUCATIONAL         AND

2            PROFESSIONAL EXPERIENCE.

3    A.      I earned a Bachelor of Science Degree in Electrical Engineering from

4            Louisiana State University, where I graduated in 1970. I was awarded a

5            Master’s Degree in Engineering Science from Lamar University in 1975. I

6            began my utility career of 41 years in 1970 when I joined ETI, formerly

7            Entergy Gulf States, Inc. (“EGSI”), which was formerly Gulf States Utilities

8            Company (“GSU”), as a planning engineer.              I have been with the

9            Company since that time.

10                   I was named plant manager at Sabine Plant in Bridge City, Texas in

11           1979, and later was promoted to the position of general manager–

12           production with responsibility for the operation of all GSU’s non-nuclear

13           generating plants in both Texas and Louisiana. Following the merger of

14           GSU into Entergy Corp. in 1993, I was appointed director of the Southern

15           Region, overseeing six fossil-fueled power plants.        A year later, I was

16           assigned a similar post with responsibility for the Eastern Region,

17           overseeing eleven fossil-fueled power plants. In June of 1997, I became

18           Director–Southwest Franchise in EGSI’s distribution group. I was named

19           to my current position of President and CEO of ETI in October 1998.

20                   In my current position, I have financial responsibility for all of ETI’s

21           assets, including generation, transmission, distribution, and customer

22           service. I am directly responsible for the day-to-day operation of ETI’s

23           Distribution and Customer Service Organization, the discrete organization




2011 ETI Rate Case                                                         3-4
     Entergy Texas, Inc.                                                                   Page 3 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


1             within ETI that is responsible for the distribution and customer service-

2             related functions in ETI’s service territory.              I exercise oversight of

3             distribution   operations      and    customer      service    from    the    point   of

4             interconnection of ETI’s distribution lines with its transmission lines down

5             to the customer’s meter.         My responsibilities also include oversight of

6             economic development, as well as regulatory and governmental affairs.

7                     While I have financial responsibility for the generation and

8             transmission assets of ETI, I do not have the day-to-day operational

9             responsibilities for the generation and transmission assets, which assets

10            are managed and operated by separate organizations within the

11            Entergy System.2

12

13                               II.     PURPOSE OF TESTIMONY

14   Q.       WHAT IS THE PURPOSE OF YOUR TESTIMONY?

15   A.       I will discuss why the Company is filing this case, provide a brief

16            description of the major components of the Company’s filing, and present

17            an overview presentation of the case and supporting witnesses. I also

18            sponsor the Utility and Executive Management class of affiliate costs.




     2
          The Operating Companies, together with their resources and facilities, are referred to as the
          “Entergy System.”




2011 ETI Rate Case                                                                3-5
     Entergy Texas, Inc.                                                       Page 4 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


1    Q.      DO YOU SPONSOR ANY SPECIFIC RATE FILING PACKAGE (“RFP”)

2            SCHEDULES?

3    A.      Yes. The schedules I sponsor are as follows:

4                   Schedule F – Description of Company;

5                   Schedule H – Engineering Information;

6                   Schedule T – Notice;

7                   Schedule U – Compliance with PUCT Orders;

8                   Schedule V – Request for Waiver of RFP Requirements; and

9                   Schedule W – Confidentiality Disclosure Agreement.

10

11   Q.      DO YOU SPONSOR ANY EXHIBITS?

12   A.      Yes.    I sponsor the exhibits listed in the Table of Contents to my

13           testimony.

14

15   Q.      HOW IS THE REMAINDER OF YOUR TESTIMONY ORGANIZED?

16   A.      In Section III, I provide an overview of the filing, including the reasons for

17           the filing, a summary of this filing, and the Company’s anticipated future

18           expenditures. Section IV describes the presentation of the case, including

19           a list of witnesses and the content of their testimony. Section V is the

20           presentation of the affiliate class that I support—the Utility and Executive

21           Management class of services. Section VI concludes my testimony.




2011 ETI Rate Case                                                       3-6
     Entergy Texas, Inc.                                                            Page 5 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case



.1                               111.        OVERVIEW OF FILING

 2   Q.      WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY?

 3   A.      In this section, I discuss why the Company is making this filing and

 4           provide a brief summary of the filing.                 also generally discuss the

 5           Company's anticipated future expenditures.

 6

 7                                      A.      Reason for Filing

 8   Q.      WHY IS ETI MAKING THIS FILING?

 9   A.      Since the June 30, 2009 close of the test year in ETl's last base rate case,

10           the Company has made substantial investments in transmission and

11           distribution infrastructure and incurred significant increases in purchased

12           power costs to reliably serve its customers.              The Company has also

13           completed    a new depreciation           study that demonstrates that the

14           Company's current depreciation rates, and resulting annual depreciation

15           expense, are too low.           The relief requested in this case is needed to

16           address these substantial and recent incremental costs, and to provide the

17           Company a reasonable opportunity to earn a reasonable return on

18           invested capital.

19

20

21           RIDER?

22   A.

2



2011 ETI Rate Case                                                            3-7
          Entergy Texas, Inc.                                                                  Page 6 of 38
          Direct Testimony of Joseph F. Domino
          2011 Rate Case


     1            power      CQ~ts   Eoi:.   the reasor:iS-explained HT-detail by Company wit11es?

     2            Phillip R. May and Robert R. Cooper, the Company's resource y,<ottlolio
                                                                                               /
     3            relies heavily on purchased power contracts to meet its ,incremental
                                                                                           /

     4            resource requirements.            The significant regulatory   la~ssociated         with
                                                                                 /


     5            recovering these costs through successive base rC}t{cases is expensive

     6            in and of itself, and results in rates that are    a~~ stale by the time they
                                                                    //'

     7            become effective.             A purchased po er rider would address those

     8            concerns in that it would avoid t           need for serial base rate cases and

     9            shield both the Comp/                a its customers from   large over- and under-

 10               recoveries that are Q sible under the current regulatory system. Further,

 11               as Mr. May di         usses, timely recovery of purchased power capacity costs

 12               will aff      flexibility to make use of the variety of resources, suppliers, and

 13

 14

 15       Q.      IS THE COMPANY ALSO MAKING A PROPOSAL THAT AFFECTS THE

 16               WAY IT RECOVERS TRANSMISSION- AND DISTRIBUTION-RELATED

 17               COSTS?

 18       A.      The Company is not proposing a transmission cost recovery factor

 19               ("TCRF") or a distribution cost recovery factor ("DCRF") in this case, but
..
 20               the Company is seeking to establish baseline values that will be identified

 21               and used on a prospective basis in conjunction with later implementation

 22               of those factors. Company witness Heather G. LeBlanc addresses these

 23               baselines in her direct testimony.




     2011 ETI Rate Case                                                              3-8
     Entergy Texas, Inc.                                                              Page 7 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


1    Q.      CAN YOU EXPLAIN IN MORE DETAIL WHAT IS DRIVING THE

2            MAGNITUDE OF THE INCREASE, PARTICULARLY GIVEN THAT THE

3            COMPANY RECENTLY IMPLEMENTED A BASE RATE INCREASE?

4    A.      The Company’s last base rate change (Docket No. 37744) resulted in a

5            two-step rate increase, the last part of which became effective as of

6            May 2, 2011, and that case was an important step in addressing ETI’s

7            financial health at that time. However, since the end of the test year for

8            that base rate case, ending June 30, 2009, the Company’s projected third-

9            party purchased power costs have more than doubled with an increase of

10           over $36 million. Between July 2009 and June 2011, the Company has

11           completed      $113.6 million     in    transmission     capital     projects   and

12           $148.2 million in distribution line and distribution-related general plant

13           additions.3 At the same time, those increased expenses are outpacing

14           load growth, which has been low since the end of the last test year (on a

15           weather-adjusted basis). In addition, the depreciation study filed in this

16           case shows that current depreciation rates are understated, justifying an

17           addition of $16.2 million to ETI’s revenue requirement.4




     3
          Company witnesses Shawn B. Corkran and Mark F. McCulla discuss the additions in
          distribution and transmission plant since the Company’s last rate case. Mr. Corkran also
          addresses the Company’s recent reliability statistics.
     4
          Company witness Dane Watson discusses the depreciation study.




2011 ETI Rate Case                                                              3-9
     Entergy Texas, Inc.                                                       Page 8 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


1    Q.      ARE THERE OTHER FACTORS INDICATIVE OF THE INADEQUACY OF

2            THE COMPANY’S CURRENT RATES?

3    A.      Yes, there are.      As reported in the Commission’s earnings monitoring

4            report for 2010, ETI had a return on equity of only 7.10%, which is 303

5            basis points short of the 10.125% ROE authorized in the Company’s last

6            rate case.

7

8                                  B.       Summary of the Filing

9    Q.      WHAT RELIEF IS THE COMPANY REQUESTING?

10   A.      The Company requests a total annual base rate and rider increase of

11           $111.8 million, which is exclusive of changes in charges for miscellaneous

12           electric services.

13

14   Q.      WHAT ARE THE MAJOR COMPONENTS OF THE COMPANY’S

15           REQUEST?

16   A.      The filing is made up of the following major components:

17           1.      The total annual rate increase of $111.8 million, or 15.32% (when

18                   calculated on base rate and rider revenues), reflecting costs

19                   recorded in Test Year July 2010 through June 2011 as adjusted for

20                   known and measurable changes.

21           2.      Approval to implement a rider to recover all purchased capacity

22                   costs and certain other costs, including future incremental amounts.

23                   That rider is designed to recover $272.7 million annually. In the




2011 ETI Rate Case                                                      3-10
     Entergy Texas, Inc.                                                        Page 9 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


1                    event the Commission rejects the Company’s request to recover

2                    purchased power through a rider, the Company requests that the

3                    adjusted test year level of expense be included in base rates.

4                    Company witness May addresses the need for this rider and the

5                    costs to be recovered through this rider.

6            3.      The Company is seeking to reconcile approximately $1.3 billion in

7                    fuel and purchased power expense in this proceeding, reconciling

8                    the period from July 2009 through June 2011.

9            4.      Establishing of base line values for future implementation of a

10                   TCRF and DCRF as authorized by PURA.

11

12   Q.      WHAT IS THE EFFECT OF THE REQUESTED RATE INCREASE,

13           INCLUSIVE OF BASE RATES AND RIDERS, ON THE TYPICAL

14           RESIDENTIAL CUSTOMER?

15   A.      Residential rates will increase $14.37 per month for 1000 kilowatt-hours

16           (“kWh”).

17

18                   C.    The Company’s Anticipated Future Expenditures

19   Q.      IS THIS CASE IMPORTANT WITH REGARD TO THE COMPANY’S

20           ANTICIPATED FUTURE EXPENDITURES?

21   A.      Yes. In order to maintain and further improve its level of service reliability

22           and to facilitate planned upgrades and expansion, the Company will

23           continue to invest in capital projects. ETI’s capital budget reflects plans to




2011 ETI Rate Case                                                       3-11
     Entergy Texas, Inc.                                                     Page 10 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


1            invest approximately $664 million in capital projects over the years 2012

2            through 2014. The Company anticipates substantial investment related to

3            growth in its service area, particularly growth in ETI’s Western Region,

4            which includes Conroe and The Woodlands.          Some of those capital

5            projects include costs for “storm hardening” in the coastal areas and other

6            areas that are more susceptible to flooding and/or high winds during

7            severe weather events, and which would benefit from such measures. A

8            primary purpose of storm hardening is to build stronger facilities in an

9            effort to mitigate the damage caused by severe weather, which can speed

10           restoration times.     Of the $664 million planned capital expenditures,

11           approximately $388 million is for maintenance of existing assets.       The

12           remaining $276 million is associated with other investments such as

13           environmental compliance spending, plant upgrades, and transmission

14           upgrades and system improvements.

15                   ETI also must address the continued need for supply-side

16           resources.    Granting the rate relief requested in this case will provide

17           important financial support as ETI takes on these new investments and

18           expenditures. ETI’s customers are expected to benefit from a financially

19           healthy company that can access capital markets on favorable terms.




2011 ETI Rate Case                                                    3-12
     Entergy Texas, Inc.                                                    Page 11 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


1    Q.      PLEASE PROVIDE FURTHER EXPLANATION REGARDING ETI’S

2            EXPECTED EFFORTS TO OBTAIN SUPPLY-SIDE RESOURCES.

3    A.      Resource planning for the Entergy System, including each Operating

4            Company, is designed to achieve the right mix of resources to serve

5            customer load shape requirements at the lowest reasonable costs. As

6            explained by ETI witness Robert R. Cooper, ETI currently projects a need

7            for capacity totaling 260 MW in 2012 and 504 MW in 2013. The System is

8            systematically pursuing resource options to fill these needs and those of

9            the other Operating Companies.

10

11                   IV.   CASE PRESENTATION AND LIST OF WITNESSES

12   Q.      HOW IS THE PRESENTATION OF THE CASE ORGANIZED?

13   A.      The Company’s case is presented through the testimony of 39 witnesses.

14           The witnesses can be grouped generally into nine groups:

15                         Financial;

16                         Operations and Customer Service;

17                         Overview Affiliate;

18                         Affiliate Classes;

19                         Non-Affiliate Revenue Requirement;

20                         Cost of Service and Rate Design;

21                         Employee Compensation;

22                         Fuel Reconciliation; and




2011 ETI Rate Case                                                   3-13
     Entergy Texas, Inc.                                                    Page 12 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


1                         Rate Case Expenses.

2                    Some witnesses present testimony in support of more than one

3             subject or component of the case, and, consequently, a witness may

4             appear in more than one of these groups.       However, each witness

5             presents only one piece of testimony. A complete listing of all of the

6             witnesses and the subject(s) they address is attached to my testimony as

7             Exhibit JFD-1.

8

9    Q.      PLEASE DESCRIBE THE FINANCIAL GROUP OF WITNESSES.

10   A.      The financial group of Company witnesses includes Chris E. Barrilleaux

11           and Dr. Sam Hadaway. Mr. Barrilleaux explains the financial status of the

12           Company and the importance of adequate rates to support the Company’s

13           financial health as the Company moves forward, as well as provides the

14           Company’s proposed capital structure. Dr. Hadaway testifies as to ETI’s

15           proposed return on equity.

16

17   Q.      PLEASE DESCRIBE THE OPERATIONS AND CUSTOMER SERVICE

18           WITNESSES.

19   A.      This group includes Company witnesses Corkran, testifying regarding

20           distribution operations, Abdon F. Roman, testifying regarding customer

21           service, H. Vernon Pierce, testifying regarding miscellaneous electric




2011 ETI Rate Case                                                   3-14
     Entergy Texas, Inc.                                                                Page 13 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


1            services,5 Mark F. McCulla, discussing transmission issues, and Winfred

2            W. Garrison, discussing fossil plant operations.                  Several of these

3            witnesses also address affiliate services and costs associated with

4            distribution operations, customer service, transmission operations and

5            fossil plant operations.

6

7    Q.      PLEASE DESCRIBE THE OVERVIEW AFFILIATE WITNESSES.

8    A.      ETI is provided certain services by its affiliates. The bulk of these affiliate

9            services are provided by ESI. In order to provide assurance as to the

10           reasonableness and necessity of these service company charges, and to

11           comply with the requirements of PURA concerning proof of affiliate costs,

12           a large portion of the case is devoted to presenting and supporting the

13           affiliate costs associated with services provided by these affiliates. The

14           Company’s use of a service company affiliate and the treatment of the

15           associated costs are discussed in greater detail elsewhere in my

16           testimony as well as in the testimony of other Company witnesses.

17                   The first set of affiliate witnesses are the overview affiliate

18           witnesses: Stephanie B. Tumminello, Jeanne J. Kenney, and Donna S.

19           Doucet.




     5
          The proposed changes in miscellaneous electric service charges discussed by Mr. Pierce will
          result in an approximate revenue increase of $911,000.




2011 ETI Rate Case                                                               3-15
     Entergy Texas, Inc.                                                       Page 14 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


1                   Ms. Tumminello supports the propriety of ESI affiliate cost

2                    allocation methods, and the necessity for, benefits of, and absence

3                    of duplication in the services provided by ESI to the Company.

4                    Ms. Tumminello is also the ESI affiliate classes overview witness.

5                    She describes the Entergy Corp. corporate structure, explains the

6                    ESI billing methods for assigning costs, and explains how affiliate

7                    costs are presented in the schedules and exhibits in the case.

8                    Finally, Ms. Tumminello addresses benchmarking that applies at

9                    the overall service company (ESI) level.

10                  Ms. Kenney discusses benchmarking of ETI’s 2008, 2009, and

11                   2010 non-production O&M expense compared to the electric utility

12                   industry.

13                  Ms. Doucet explains and supports the reasonableness of the

14                   Entergy Companies’ budgeting process.

15

16   Q.      THE NEXT GROUP IS THE AFFILIATE CLASSES GROUP. PLEASE

17           DESCRIBE THIS GROUP.

18   A.      These witnesses, in general, present the explanation and support for the

19           affiliate costs being requested by the Company in this case. As indicated

20           previously, certain witnesses appearing in other groups also support

21           affiliate costs.    The affiliate classes group and the respective affiliate

22           classes they support are:




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     Entergy Texas, Inc.                                                      Page 15 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


1                   Julie F. Brown—Information Technology;

2                   Patrick Cicio—Energy and Fuel Management;

3                   Shawn B. Corkran—Transmission and Distribution Support and
4                    Distribution Operations;

5                   Donna S. Doucet—Financial Services;

6                   Walter C. Ferguson—Federal PRG Affairs;

7                   Patricia A. Galbraith—Tax Services;

8                   Kevin G. Gardner—Human Resources;

9                   Winfred W. Garrison—Fossil Plant Operations;

10                  Chester N. Herrington—Internal and External Communications;

11                  Joseph Hunter—Supply Chain;

12                  Phillip R. May—Regulatory Services;

13                  Mark F. McCulla—Transmission Operations;

14                  Steven C. McNeal—Treasury Operations;

15                  Thomas C. Plauché—Administration;

16                  Rory Roberts—ESI Income Taxes;

17                  Abdon F. Roman—Customer Service Operations, Environmental
18                   Services, and Retail Operations;

19                  Robert D. Sloan—Legal Services;

20                  Stephanie B. Tumminello—Depreciation,          Service     Company
21                   Recipient Offsets, and Other Expenses; and

22                  Myself—Utility and Executive Management.




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     Entergy Texas, Inc.                                                       Page 16 of 38
     Direct Testimony of Joseph F. Domino
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1    Q.      PLEASE DESCRIBE THE NON-AFFILIATE REVENUE REQUIREMENT

2            GROUP OF WITNESSES.

3    A.      These witnesses include:

4                   Michael P. Considine—Regulatory and Tax Accounting, Revenue
5                    Requirement Issues, Pensions and other Post-Retirement Benefits,
6                    and Pro Forma Adjustments;

7                   Patricia A. Galbraith—ETI Property Tax Pro Forma;

8                   Jay Joyce—Lead Lag Study Review;

9                   Rory L. Roberts—Income Tax;

10                  Dane Watson—Depreciation; and

11                  Gregory S. Wilson—Property Insurance Reserve.

12

13   Q.      PLEASE DESCRIBE THE COST OF SERVICE AND RATE DESIGN

14           GROUP.

15   A.      Mr. Considine is the overall accounting witness for the Company and

16           presents the Company’s revenue requirement.            Heather G. LeBlanc

17           supports the Class Cost of Service study (and the proposed Purchased

18           Power Recovery Rider).         Mr. Richard A. Lynch supports the weather-

19           related   adjustments     to   the   Test   Year billing determinants, and

20           Myra Talkington presents the Company’s rate design, class cost

21           allocation, and rate schedules and tariff.




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     Entergy Texas, Inc.                                                       Page 17 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


1    Q.      HOW      HAVE     YOU     ADDRESSED         THE   ISSUE    OF     EMPLOYEE

2            COMPENSATION LEVELS?

3    A.      Company witness Gardner, who was identified above as addressing

4            Human Resources affiliate charges, also provides benchmarking support

5            for total compensation among the various categories of employees. He

6            demonstrates that total annual compensation for all categories of

7            employees, taken as a whole, is reasonable and necessary, based on

8            market surveys. He also demonstrates that awards under the annual and

9            long-term incentive plan, and employee benefit programs and levels,

10           are reasonable.

11                   In addition to Mr. Gardner, the Company presents Dr. Jay C.

12           Hartzell, an outside expert from the University of Texas, who examines the

13           bases of the Commission’s past decisions regarding disallowance of

14           “financially-based” incentive compensation.        While the Company is

15           cognizant of those past decisions, it continues to urge further examination

16           of the merits and details of that policy.

17

18   Q.      WHO     ARE     THE     WITNESSES       PRESENTING        THE     FUEL   AND

19           PURCHASED POWER RECONCILIATION PORTION OF THE CASE?

20   A.      The fuel reconciliation witnesses include:

21                  Robert R. Cooper—Long Term Planning and Long-Term Purchased
22                   Power;

23                  Devon S. Jaycox—Economic Dispatch for the Reconciliation
24                   Period;




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     Entergy Texas, Inc.                                                        Page 18 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


1                   Karen Macllvoy—Reconcilable Gas Purchases, and Gas and Oil
2                    Base Rate Components;

3                   Margaret McCloskey—Over/Under            Recovery      Balance       for
4                    Reconcilable Fuel;

5                   Michelle H. Thiry—Reconcilable Fuel Overview and Short-Term
6                    Purchased Power;

7                   Ryan Trushenski—Reconcilable       and    Non-Reconcilable        Coal
8                    Expense; and

9                   Gregory R. Zakrzewski—Fuel Accounting.

10

11   Q.      WHO PRESENTS THE COMPANY’S RATE CASE EXPENSES?

12   A.      Mr. Stephen F. Morris presents the Company’s rate case expenses

13           associated with outside attorneys and consultants.             Mr. Considine

14           presents the Company’s rate case expenses associated with ETI, ESI

15           employees, and miscellaneous expenses.

16

17           V.      THE UTILITY AND EXECUTIVE MANAGEMENT CLASS OF
18                                 AFFILIATE COSTS

19   Q.      WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY?

20   A.      The purpose of this section of my testimony is to support the Company’s

21           request for recovery of affiliate costs associated with the Utility and

22           Executive Management class of affiliate services. I will demonstrate that

23           the costs for this class are reasonable and necessary, and that the

24           amounts billed to ETI for these services are billed to the other affiliates

25           using the same methodology and at prices that are no higher than those




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     Entergy Texas, Inc.                                                       Page 19 of 38
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1            charged to other affiliates for the same or similar services. My testimony

2            will also show that the prices for these services that have been charged to

3            ETI represent the actual cost for these services.

4

5    Q.      PLEASE PROVIDE A BRIEF DESCRIPTION OF THIS CLASS.

6    A.      The ESI Utility and Executive Management class is comprised of

7            30 departments. Generally, however, this class can be broken into two

8            groups of services:     The Utility Management group and the Executive

9            Management group.         As described in more detail below, the Utility

10           Management group provides executive leadership and management for

11           the regulated utility operations, and the Executive Management group

12           provides overall oversight of the operations of all Entergy Companies,

13           including regulated legal entities, and stewardship of the corporate assets.

14

15   Q.      WHAT IS THE TOTAL ETI ADJUSTED AMOUNT FOR THIS CLASS OF

16           SERVICES?

17   A.      The Total ETI Adjusted amount for the Utility and Executive Management

18           class of affiliate services is $1,939,228. Table 1 below shows for the class

19           the following information:




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     Entergy Texas, Inc.                                                           Page 20 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


              Total Billings                 Dollar amount of total Test Year billings from
                                             ESI to all Entergy Companies, plus the dollar
                                             amount of all other affiliate charges that
                                             originated from any Entergy Company. This
                                             is the amount from Column (C) of the cost
                                             exhibits JFD-A, JFD-B, and JFD-C.
              Total ETI Adjusted             ETI’s adjusted amount for electric cost of
              Amount                         service after pro forma adjustments and
                                             exclusions.
              % Direct Billed                The percentage of the ETI adjusted test year
                                             amount that was billed 100% to ETI.
              % Allocated                    The percentage of the ETI adjusted test year
                                             amount that was allocated to ETI.

                                               Table 1

                                                              Total ETI Adjusted
              Class              Total Billings          Amount      % Direct           %
                                                                                    Allocated
              Utility and
              Executive            $30,702,565       $1,939,228          4.34%     95.66%
              Management


1    Q.      PLEASE      DESCRIBE           THE   EXHIBITS        THAT    SUPPORT          THE

2            INFORMATION INCLUDED IN TABLE 1.

3    A.      Attached to my testimony are exhibits showing the calculation of the Total

4            ETI Adjusted amount for the Utility and Executive Management Class. In

5            my Exhibit JFD-A, the information is shown broken down by the

6            departments comprising the class. My Exhibit JFD-B shows the same

7            information broken down by project code and the billing method assigned

8            to each project code.          My Exhibit JFD-C shows the information by

9            department, project code, and the billing method assigned to the project




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     Entergy Texas, Inc.                                                       Page 21 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


1            code.    For each exhibit, the amounts in the columns represent the

2            following information:

             Column (A) –               Dollar amount of total Test Year billings and
             Support                    charges from ESI to all Entergy Business Units to
                                        ETI, plus the dollar amount of all other affiliate
                                        charges to ETI that originated from any Entergy
                                        Business Unit.

             Column (B) –      Dollar amount that was included in the service
             Service   Company company recipient allocation. Service company
             Recipient         recipient charges are the cost of services that ESI
                               provides to itself, which in turn, are charged to
                               affiliates that receive those services. The service
                               company recipient allocation process is described
                               in the testimony of Company witness Tumminello.

             Column (C) –               Represents the sum of Columns (A) and (B).
             Total

             Column (D) –       That portion of Column (C) that was billed and
             All Other Business charged to Business Units other than ETI.
             Units

             Column (E) –               Represents the difference between Columns (C)
             ETI Per Books              and (D).

             Column (F) –               Represents amounts that are excluded from ETI
             Exclusions                 electric cost of service. The exclusions are
                                        described in the testimony of Company witness
                                        Tumminello.

             Column (G) –               Pro Forma Amounts include adjustments for
             Pro Forma Amount           known and measurable changes, and corrections.

             Column (H) –               ETI adjusted amount requested for recovery in
             Total ETI Adjusted         this case for this class (Column (E) plus Columns
                                        (F) and (G)).




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     Entergy Texas, Inc.                                                        Page 22 of 38
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1                    In her direct testimony, Ms. Tumminello describes the calculations

2            that take the dollars of support services in Column (E) to the Total ETI

3            Adjusted numbers shown on Column (H).

4

5    Q.      ARE THERE ANY PRO FORMA ADJUSTMENTS TO THIS CLASS?

6    A.      Yes.     The pro forma adjustments for the Utility and Executive

7            Management class of services are shown on Exhibit JFD-D, which also

8            identifies the Company witnesses who sponsor those pro forma

9            adjustments.

10

11   Q.      WHAT ARE THE MAJOR COST COMPONENTS OF THIS CLASS?

12   A.      The major cost components are as follows:

                                            Table 2
                        Cost Component        Utility and Executive
                                                   Management
                                                            % of Total
                        Payroll and          $956,108        49.3%
                        Employee Costs
                        Outside Services     $738,073       38.1%
                        Office and           $97,947         5.1%
                        Employee
                        Expenses
                        Other                $23,427         1.2%
                        Service              $123,674        6.4%
                        Company
                        Recipient
                        Total               $1,939,228       100%




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     Entergy Texas, Inc.                                                           Page 23 of 38
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1    Q.      WHAT IS THE IMPORTANCE OF THESE COST CATEGORIES?

2    A.      This breakout provides an additional view of the costs in this class. The

3            breakout is significant, moreover, because other Company witnesses in

4            this case provide additional overall support for the affiliate costs included

5            in several of these categories. For instance, in this class, the Payroll and

6            Employee Costs component is the largest component of the class. With

7            respect to this component, Company witness Gardner supports the market

8            competitiveness and overall reasonableness of salary and benefits costs.

9                    “Outside Services” pertains to services provided by non-Entergy

10           Companies employees and firms, such as outside consultants and

11           vendors.    This is the second largest component of this class.             I later

12           address some of the activities performed by these consultants in my

13           description of the Utility Management and Executive Management groups.

14                   “Office and Employee Expenses” covers the costs of maintaining

15           work spaces and office supplies. Company witness Plauché addresses

16           these types of costs in more detail in his direct testimony.

17                   The “Service Company Recipient” row of the table pertains to costs

18           common throughout ESI, such as IT, rents, and human resources, which

19           are primarily incurred to support ESI operations. These costs are spread

20           to all affiliate classes as explained by Company witness Tumminello.




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     Entergy Texas, Inc.                                                       Page 24 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


1    Q.      WHAT AREAS DO YOU ADDRESS IN THE REMAINDER OF YOUR

2            TESTIMONY IN THIS SECTION?

3    A.      I provide further description of the services provided in the two Utility and

4            Executive Management groups of services. I also address the necessity

5            and reasonableness of the services and level of charges associated with

6            this class. Finally, I discuss the predominant billing methods included this

7            class and describe why those methods are reasonable.

8

9    Q.      WHAT TYPES OF SERVICES DOES THE UTILITY MANAGEMENT

10           GROUP PROVIDE?

11   A.      This group provides executive leadership and management for the

12           regulated utility operations, including Customer Service Support, Sales

13           and Marketing, the State Presidents, Utility Group Safety and Regulatory

14           Affairs, as well as the operation, engineering, construction and

15           maintenance of the distribution system.         This group also provides

16           executive oversight and guidance related to the Fossil, Transmission and

17           System Planning organizations. Also provided by this group are access to

18           consulting services, including the retention of outside consultants, required

19           for federal and state regulatory matters, including those related to open

20           access of the Entergy Companies’ transmission system and the

21           Independent Coordinator of Transmission.       The group further provides

22           oversight for Entergy Continuous Improvement, corporate performance

23           measurement efforts and ongoing O&M benchmarking.                  Consulting




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     Entergy Texas, Inc.                                                      Page 25 of 38
     Direct Testimony of Joseph F. Domino
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1            activities for the development of alternate technologies and power

2            generation projects are also part of this group.

3                    In summary, activities include providing executive guidance with

4            respect to the development of short-term and long-term plans to ensure

5            the continued reliable operation of the regulated electric system, and

6            performance management to monitor and support improvement in those

7            operations. This function provides guidance and leadership for federal,

8            state and local matters common to all jurisdictions and avoids

9            unnecessary     duplication    of   these   management   activities.     This

10           organizational structure enables management to provide these services in

11           a cost-effective manner.

12

13   Q.      WHAT TYPES OF SERVICES DOES THE EXECUTIVE MANAGEMENT

14           GROUP PROVIDE?

15   A.      This group provides overall oversight of the operations of all Entergy

16           Companies, including regulated legal entities, and stewardship of the

17           corporate assets. The class further provides policy direction, including the

18           appropriate use of consulting services, with respect to regulatory, legal

19           and strategic decisions. During the Test Year, this function coordinated

20           the Entergy Companies’ responses to various legal, regulatory, and policy

21           issues.    This function provides guidance and leadership for matters

22           common to all jurisdictions and avoids unnecessary duplication of these




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     Entergy Texas, Inc.                                                       Page 26 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


1            management       activities.     This   organizational   structure    enables

2            management to provide these services in a cost-effective manner.

3

4    Q.      DOES     THE     UTILITY       AND   EXECUTIVE    MANAGEMENT          CLASS

5            PROVIDE NECESSARY SERVICES?

6    A.      Yes.    The highly integrated and extensively regulated nature of the

7            Entergy Companies’ multi-jurisdictional utility operations requires a

8            centralized management structure that provides leadership, guidance and

9            decision-making as well as making it necessary to coordinate legal,

10           regulatory, and policy matters on a system-wide basis.        This supports

11           consistent implementation of operational practices that provide efficiencies

12           and ensures that services are not duplicated within the individual

13           organizations or within the individual Operating Companies.               The

14           leadership and direction provided by this centralized management

15           structure have been effective, as shown by the achievement of the

16           operational performance results described by Mr. Corkran.

17

18   Q.      PLEASE ADDRESS THE STAFFING LEVEL TRENDS FOR 2008, 2009,

19           2010, AND THE TEST YEAR.

20   A.      Staffing levels for the Utility and Executive Management class that I

21           support are shown in Table 3, below.




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     Entergy Texas, Inc.                                                           Page 27 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


                                                      Table 3
                     Class                  20086            2009        2010           Test
                                                                                        Year
                Utility and Executive         36             39            43            42
                Management Class


1    Q.      WHAT WERE THE COST TRENDS FOR THE UTILITY AND EXECUTIVE

2            MANAGEMENT CLASS THAT YOU SUPPORT FOR THE LAST THREE

3            YEARS AS COMPARED TO THE TEST YEAR?

4    A.      Table 4 below shows the total affiliate O&M charges to ETI for each of the

5            past three calendar years and the Test Year for this class of service.

6            These charges have been adjusted to remove costs billed to ETI from

7            nuclear, gas, and “spin off” department codes. Charges to ETI from these

8            departments have also been removed from ETI’s Test Year cost

9            of service.

                                                   Table 4
                                  2008              2009            2010           Test Year
              Total O&M           $2.5              $2.1            $2.3             $2.2
              (in millions)


10   Q.      PLEASE EXPLAIN THE TREND IN STAFFING LEVELS AND COSTS.

11   A.      As shown in Tables 3 and 4, there is a cumulative staffing increase of

12           six personnel between 2008 and the Test Year, while O&M costs over that

13           same period have remained relatively level. The higher O&M costs in


     6
          The 2008, 2009, and 2010 figures are year-end (December 31) headcounts. The Test Year
          figure is the headcount as of June 30, 2011.




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     Entergy Texas, Inc.                                                         Page 28 of 38
     Direct Testimony of Joseph F. Domino
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1            2008 were primarily due to activities associated with Qualified Power

2            Region regulatory proceedings in Texas.

3                    The cumulative increase in staffing levels is the result of occasional

4            reorganizations and the creation of new departments and projects. The

5            majority of the increase in staffing levels is due to the addition of the

6            Critical Infrastructure Protection department in 2010.              The Critical

7            Infrastructure Protection department has overall responsibility for leading

8            the Entergy Companies’ implementation of, and adherence to, mandatory

9            North American Electric Reliability Corporation Critical Infrastructure

10           Protection standards designed to protect Entergy Critical Cyber Assets

11           that support the reliable operation of the Bulk Electric System.

12

13   Q.      ARE THESE NECESSARY SERVICES PROVIDED AT A REASONABLE

14           COST?

15   A.      Yes. First, the costs reflected in this class are subject to the cost control

16           and monitoring process more fully described in the testimony of Company

17           witness Doucet.     The process includes a budgeting process aimed at

18           establishing   long-range      financial   plans,   based   upon     prior   year

19           performance and future objectives. The budgeting process, which is a

20           top-down as well as a bottom-up process, includes a detailed budgeting

21           phase that requires the input of each organization within ETI, including my

22           review and input as the President of ETI.           The process assures the

23           meaningful input of the ETI organizations utilizing the affiliate services.




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     Entergy Texas, Inc.                                                       Page 29 of 38
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1                    The cost control and monitoring process also includes a cost

2            reporting stage that requires evaluation by ETI management of the

3            variance between actual and budgeted amounts.           As the executive

4            ultimately accountable for ETI’s costs, including the costs associated with

5            services provided by its affiliate service company, I am responsible for

6            monitoring the reporting stage and reviewing all variances.

7                    This budgeting and reporting process supports accountability

8            between ETI and its service company affiliates with respect to its use of

9            affiliate services and the associated costs that are charged to ETI. The

10           process provides assurance that affiliate costs are reasonable, including

11           the costs for this class.

12                   In addition, as discussed above, the headcount and cost trends

13           support the reasonableness of these costs. The cumulative increase in

14           staffing levels includes a reasonable increase of six positions over four

15           years, and simply reflects normal corporate activities, which includes

16           occasional reorganizations and new departments — such as the Critical

17           Infrastructure Protection department — and projects to address emerging

18           technologies,       environmental     and      safety         issues,     and

19           regulatory expectations.

20                   Moreover, the reasonableness of the costs associated with the

21           Utility and Executive Management class is supported by the benchmarking

22           analyses sponsored by Company witnesses Kenney. Eighty-nine percent

23           (89%) of the costs associated with this affiliate class are charged to A&G




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     Entergy Texas, Inc.                                                                 Page 30 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


1            FERC accounts and included in Ms. Kenney’s analysis of A&G costs

2            among utilities throughout the United States.7                Ms. Kenney’s analysis

3            demonstrates that the level of ETI’s A&G costs was at 68% of the industry

4            average on a cost per MWh basis for 2008, 65% of the industry average

5            on a cost per MWh basis for 2009, and 70% of the industry average on a

6            cost per MWh basis for 2010. Those levels equated to a ranking of 28th,

7            27th, and 33rd, from least cost to the greatest, among the 100-plus utilities

8            included in the benchmarking for the years 2008 through 2010,

9            respectively. That places ETI in the top of the second quartile in each

10           year.

11                   Based on the cost control process, the historical cost and staff

12           trends, and the benchmarking performed by Ms. Kenney, in addition to my

13           previous discussion of the benefits of non-duplication of the services

14           provided by a centralized service company, I conclude that the costs

15           associated      with    the    Utility   and     Executive      Management         class

16           are reasonable.




     7
         As discussed by Ms. Kenney, there were 107 electric operating companies, including ETI, in
         the study for 2008, and 116 electric operating companies, including ETI, in the study for 2009
         and 2010.




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     Entergy Texas, Inc.                                                     Page 31 of 38
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1    Q.      IS THE UTILITY AND EXECUTIVE MANAGEMENT CLASS OF

2            AFFILIATE SERVICES DUPLICATED BY ETI?

3    A.      No.     By having these services provided through a central organization

4            (ESI), ETI and each of the other Entergy Operating Companies avoid the

5            need to maintain their own contingent of personnel to perform these

6            services and avoid the costs associated with maintaining that personnel.

7

8    Q.      HOW ARE THE COSTS OF THIS CLASS OF SERVICES BILLED TO

9            ETI?

10   A.      Exhibit JFD-B shows all of the costs included in this class broken down by

11           project code and shows the billing method associated with each

12           project code.

13

14   Q.      ON WHAT BASIS ARE COSTS IN THIS CLASS ALLOCATED?

15   A.      The costs for the services included in this class are collected in one or

16           more project codes. As Ms. Tumminello explains, a billing method for the

17           project code is selected based upon cost causation, and while several

18           organizations may bill to a single project code, only one billing method is

19           assigned to each project code. Through the use of a single billing method,

20           the costs of all services performed under a project code are allocated

21           among the Entergy Operating Companies using the same criteria, at cost.

22           This ensures that all Entergy Operating Companies that cause costs to be

23           incurred and benefit from the service pay their appropriate proportion of




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     Entergy Texas, Inc.                                                       Page 32 of 38
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1            the costs. It also ensures that the Entergy Operating Companies are, in

2            total, charged no more and no less than one hundred percent of the costs

3            for services provided under the project code. Finally, the use of a single

4            billing method ensures that each Entergy Operating Company is paying

5            the same price for the same service, and that the price charged to ETI for

6            the services is no higher than the price charged by ESI to other affiliates

7            for the same or similar services and represents the actual cost of

8            the services.

9

10   Q.      ABOVE YOU NOTED THAT 4.34% OF THE COSTS IN THIS CLASS

11           WERE      DIRECTLY       BILLED   TO   ETI,   AND     THE    REMAINDER

12           ALLOCATED. PLEASE DISTINGUISH BETWEEN COSTS THAT ARE

13           “DIRECT” BILLED VERSUS COSTS THAT ARE “ALLOCATED” TO THE

14           ENTERGY COMPANIES.

15   A.      Whenever appropriate, costs are direct billed to ETI and other affiliates.

16           This means the services provided (and associated costs) are caused by,

17           and benefiting, only ETI or whatever entity is the sole cause of the

18           services, and associated costs, provided. Only when costs are incurred

19           that are caused by ETI and one or more of the other Entergy Companies

20           are such costs billed by ESI to ETI using an allocation method.




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     Entergy Texas, Inc.                                                       Page 33 of 38
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1    Q.      WHAT ARE THE PREDOMINANT BILLING METHODS USED FOR THIS

2            CLASS OF SERVICES?

3    A.      For this class of services, the following billing methods are used to bill

4            92.57% of the costs for this class of services:

5                   “ASSTSALL” – Total Assets (35.58%);

6                   “CAPAOPCO” – System Capacity (22.49%);

7                   “CUSTEGOP” – Electric and Gas Customers (22.17%);

8                   “CUSEOPCO” – Electric Customers (8.01%);

9                   “DIRECTTX” – 100% to ETI (4.34%).

10

11   Q.      WHY IS BILLING METHOD “ASSTSALL” APPROPRIATE TO USE FOR

12           THE PROJECT CODES TO WHICH IT IS ASSIGNED?

13   A.      For project codes assigned this billing method, costs are allocated based

14           on total assets. For example, Project Code F3PCC08500 — Executive

15           VP, Operations — captures costs associated with the operations of the

16           office of the President and Chief Operating Officer, Domestic Operations,

17           of Entergy Corp. The President/COO and staff provide cross-functional

18           management and direction to the Entergy System, and services provided

19           under this project relate to the oversight of all System Operations and the

20           stewardship of corporate assets.          Billing Method “ASSTSALL” is

21           appropriate because it reflects the cause of the costs incurred, in that,

22           services provided relate to the stewardship of all the corporation’s assets.




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     Entergy Texas, Inc.                                                         Page 34 of 38
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1    Q.      WHY IS BILLING METHOD “CAPAOPCO” APPROPRIATE TO USE FOR

2            THE PROJECT CODES TO WHICH IT IS ASSIGNED?

3    A.      For the project codes assigned this billing method, costs are allocated

4            based on the fossil capacity of each Operating Company relative to the

5            fossil system capacity.        For example, Project Code F3PCCEP001 —

6            Corporate Environmental Policy — captures and manages costs

7            associated with developing and implementing environmental policies and

8            programs to support fossil operations company-wide.                The primary

9            activities conducted under this project code are the performance of

10           systematic reviews of existing, pending, and proposed environmental

11           regulations impacting the Entergy Operating Companies’ fossil operations.

12           Activities   also   include    the   development   and    implementation      of

13           environmental policies, standards, and programs as well as active

14           participation in industry coalition groups to improve environmental

15           regulations that govern the electric industry.           Because the costs

16           associated these activities are primarily associated with the Operating

17           Companies’ fossil operations, the relative size and complexity of each

18           entity is appropriately measured by fossil generating capacity, making

19           CAPAOPCO the appropriate billing method.




2011 ETI Rate Case                                                       3-36
     Entergy Texas, Inc.                                                         Page 35 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


1    Q.      WHY IS BILLING METHOD “CUSTEGOP” APPROPRIATE TO USE FOR

2            THE PROJECT CODES TO WHICH IT IS ASSIGNED?

3    A.      For the project codes assigned this billing method, costs are allocated

4            based on the number of electric and gas customers. For example, Project

5            Code F3PCE99795 — Group President - Utility Operations — captures

6            costs associated with general activities of the office of the Group President

7            - Utility Operations related to executive management and oversight of the

8            Entergy Operating Companies’ regulated utility operations. The activities

9            under this project include meetings with utility company presidents to

10           discuss day-to-day operations of the companies, Board of Directors

11           meetings and activities, and meetings with regulators and their staffs on

12           utility matters, which activities directly relate to regulated utility customers

13           served by each Operating Company.             Consequently, Billing Method

14           “CUSTEGOP” is appropriate because the relative level of activities and

15           costs are driven by the number of customers at each company.

16

17   Q.      WHY IS BILLING METHOD “CUSEOPCO” APPROPRIATE TO USE FOR

18           THE PROJECT CODES TO WHICH IT IS ASSIGNED?

19   A.      Billing Method “CUSEOPCO” allocates costs based on the number of

20           electric customers. For example, Project Code F3PPE9974S — Utility

21           ECI Continuing Improvement ESI — captures and manages costs

22           associated with the general activities of the Entergy Continuing

23           Improvement (“ECI”) department.         That department is related to the




2011 ETI Rate Case                                                        3-37
     Entergy Texas, Inc.                                                       Page 36 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


1            executive management and oversight of the various Strategic Initiatives

2            (e.g., Six Sigma, Benchmarking, ECI) in the Entergy Operating

3            Companies’ regulated utility operations.     The primary activities include

4            meetings with utility company presidents and operating departments to

5            review and discuss ECI-Entergy Continuing Improvement and other

6            Strategic Initiatives status and implementation issues. Because the focus

7            of these types of projects is on improvements in the delivery of service to

8            regulated distribution customers, the pertinent cost driver for these

9            services is the number of electric customers, and the appropriate billing

10           method is CUSEOPCO.

11

12   Q.      WHY IS BILLING METHOD “DIRECTTX” APPROPRIATE TO USE FOR

13           THE PROJECT CODES TO WHICH IT IS ASSIGNED?

14   A.      This project code directs that 100% of the charges be allocated to ETI.

15           For instance, project codes assigned to this billing method often include

16           activities in which ESI assists with ETI fillings before the Commission. In

17           such instances, it is appropriate that ESI’s charges are allocated (or billed

18           directly) 100% to ETI.




2011 ETI Rate Case                                                      3-38
     Entergy Texas, Inc.                                                       Page 37 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


1    Q.      YOU HAVE ADDRESSED THE BILLING METHODS USED TO BILL

2            92.57% OF THE COSTS ASSOCIATED WITH THIS CLASS.                        WHAT

3            ABOUT THE REMAINING 7.43% OF THE COSTS OF THIS CLASS?

4    A.      The remaining costs are billed through the use of other billing methods.

5            Given the number of billing methods, project codes, and relative dollar

6            amounts, I have not gone into detail in this discussion in an effort to keep

7            the discussion at a manageable level. However, the project codes and

8            billing methods used to bill the remaining 7.43% of the costs in this class

9            are provided in Exhibit JFD-B, discussed earlier. A reader may reference

10           this exhibit and then refer to the specific scope statement contained in

11           Ms. Tumminello’s testimony for a discussion of the particular billing

12           method used and the cost drivers for the activities captured in the

13           particular project code.

14

15   Q.      HAVE YOU DETERMINED THAT THE COSTS REFLECTED IN THE

16           REMAINING 7.43% OF COSTS ASSOCIATED WITH THIS CLASS HAVE

17           BEEN BILLED APPROPRIATELY?

18   A.      Yes. I have reviewed each of the project codes and the associated billing

19           methods used to bill the remaining 7.43% of the costs of this class. The

20           cost drivers reflected in the billing method used to bill the costs of each

21           project code are consistent with and reflect the cost drivers of the services

22           captured in each respective project code. Therefore, the price charged to

23           ETI represents the costs of the services received by ETI and is no higher




2011 ETI Rate Case                                                      3-39
     Entergy Texas, Inc.                                                   Page 38 of 38
     Direct Testimony of Joseph F. Domino
     2011 Rate Case


1            than the price charged to other affiliates for the same or similar types

2            of services.

3

4                                     VI.   CONCLUSION

5    Q.      DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?

6    A.      Yes.




2011 ETI Rate Case                                                  3-40
                                                                              Exhibit JFD-1
                                                                         2011 TX Rate Case
                                                                                Page 1 of 3
                                 November 2011 Rate Case
                               Witness and Testimony Content

                 Witness                             Testimony
                                                       Subject
       Chris E. Barrilleaux         Company’s Financial Status and Importance of
                                    Adequate Rates; Capital Structure.

       Julie F. Brown               Information Technology Affiliate Charges;
                                    Information Technology Capital Additions.

       Patrick J. Cicio             Energy and Fuel Management Affiliate Charges;
                                    Energy and Fuel Management Capital Additions;
                                    Entergy System Agreement.

       Michael P. Considine         Regulatory and Tax Accounting; Revenue
                                    Requirement Issues; Pension and OPEB
                                    Expenses; Pro Forma Adjustments.

       Robert R. Cooper             Long-Term Resource Planning; Long-Term
                                    Purchased Power Contracts.

       Shawn B. Corkran             Overall Distribution O&M Charges; Distribution
                                    Operations Affiliate Charges; Transmission and
                                    Distribution Support Affiliate Charges; Distribution
                                    Operations Capital Additions; Texas Distribution
                                    Operations; Service Quality & Service Quality
                                    Improvement; Miscellaneous Electric Services
                                    Charges.

       Joseph F. Domino             Case Overview and Presentation; Executive and
                                    Utility Management Affiliate Charges.

       Donna S. Doucet              Financial Services Affiliate Charges; Budget
                                    Process.

       Walter C. Ferguson           Federal Policy, Regulatory and Governmental
                                    Affairs Affiliate Charges.

       Patricia A. Galbraith        ETI Property Tax Pro Forma; Tax Services
                                    Affiliate Charges.

       Kevin G. Gardner             Compensation, Benefits, and Labor-Related
                                    Charges; Human Resources Affiliate Charges.




2011 ETI Rate Case                                                      3-41
                                                                        Exhibit JFD-1
                                                                   2011 TX Rate Case
                                                                          Page 2 of 3


       Winfred W. Garrison     Fossil Plant Capital Additions; Fossil Plant
                               Operations and Nelson 6 Co-Owner Service
                               Affiliate Charges; Fossil Plant Efficiency.

       Samuel C. Hadaway       Return on Equity.

       Jay C. Hartzell         Alignment of Incentive Compensation Goals and
                               Customer Benefits.

       Chester N. Herrington   Communications Affiliate Charges.

       Joseph Hunter           Supply Chain Affiliate Charges; Supply Chain
                               Capital Additions.

       Devon S. Jaycox         Reasonableness of Energy Acquisition and
                               Economic Dispatch for the Reconciliation Period.

       Jay Joyce               Lead Lag Study Review.

       Jeanne J. Kenney        FERC Form 1 non-production O&M Cost
                               Benchmarking.

       Heather G. LeBlanc      Class Cost of Service Study; Purchased Power
                               Recovery Rider; REC Rider.

       Richard A. Lynch        Weather-Normalized Demand and Energy.

       Phillip R. May          Regulatory Support Affiliate Charges; Regulatory
                               Support Capital Additions; Purchased Power
                               Recovery Rider; Competitive Generation Service

       Margaret McCloskey      Over/(Under)-Recovery Balance for Reconcilable
                               Fuel Expense.
       Mark F. McCulla         Overall ETI Transmission O&M Charges;
                               Transmission Operations Affiliate Charges;
                               Transmission Operations Capital Additions.

       Karen McIlvoy           Reconcilable Gas Purchases; Gas and Oil Base
                               Rate Components.

       Stephen C. McNeal       Treasury Operations Affiliate Charges.

       Stephen F. Morris       External Rate Case Expenses.




2011 ETI Rate Case                                                 3-42
                                                                          Exhibit JFD-1
                                                                     2011 TX Rate Case
                                                                            Page 3 of 3


       H. Vernon Pierce          Texas Retail Operations; Miscellaneous Electric
                                 Services Charges.

       Thomas C. Plauché         Administration Affiliate Charges; Capital Additions
                                 for Administration Services.

       Rory L. Roberts           ETI FIT Expense; Consolidated Tax Savings
                                 Issues; FIT Expense Affiliate Charges.

       Abdon F. Roman            Affiliate Charges for the Customer Service
                                 Operations, Environmental Services, and Retail
                                 Operations Classes; Customer Service Operations
                                 Capital Additions.
       Robert D. Sloan           Legal Services Affiliate Charges; Legal Services
                                 Capital Additions.

       Myra L. Talkington        Rate Design; Class Cost Allocation Factors; Rate
                                 Schedules and Tariffs.

       Michelle H. Thiry         Reconcilable Fuel Expense Overview; Short-Term
                                 Purchased Power Expense.

       Ryan Trushenski           Reconcilable and Non-Reconcilable Coal
                                 Expense.

       Stephanie B. Tumminello   Overview of Affiliate Structure and Transactions;
                                 FERC Form 60 Benchmarking, Explanation of
                                 Affiliate Charges Presentation; Depreciation
                                 Affiliate Charges; Service Company Recipient
                                 Offsets Affiliate Charges; Other Expenses Affiliate
                                 Charges.

       Dane Watson               Depreciation.

       Gregory S. Wilson         Recommendation for Insurance Reserve Accrual.

       Gregory R. Zakrzewski     Non-Reconcilable/Reconcilable Fuel Accounting.




2011 ETI Rate Case                                                  3-43
    This page has been intentionally left blank.




2011 ETI Rate Case                       3-44
                                                                                                                           ENTERGY TEXAS, INC.                                                                         EXHIBIT JFD-A
2011 ETI Rate Case




                                                                                                         Affiliate Billings - by Witness, Class, and Department                                                     2011 TX Rate Case
                                                                                                               For the Twelve Months Ended June 30, 2011                                                                   Page 1 of 1
                                                                                                                             Amounts in Dollars
                                                                                              (A)              (B)               (C)             (D)         (E)            (F)           (G)           (H)
                                                                                                          Total Billings
                                                                   Billing                               Service Company                                    ETI Per                    Pro Forma      Total ETI
                                           Class                   Entity      Dept         Support         Recipient           Total      All Other BU's   Books        Exclusions     Amount        Adjusted
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         CE122          1,289,256              81,310      1,370,566       1,366,479        4,086             -           (536)         3,551
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         CE12F            (19,654)                   -        (19,654)        (19,654)           -            -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         CE179          1,281,690             105,837      1,387,527       1,387,448            78          (78)             -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         CP015            208,351                    -       208,351         185,100       23,251       (23,251)             -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         CP027                  -                    -              -               -            -            -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         CP040          5,400,646             337,276      5,737,922       5,387,064     350,858         (5,438)        (7,095)      338,326
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         CP050          1,347,769              96,578      1,444,347       1,442,753        1,594           (28)        (1,058)           509
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         CP083            223,988              23,886        247,874         211,700       36,173             -            479        36,652
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         CPCA5            322,809              36,140        358,949         343,256       15,693             -            (98)       15,595
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         CPCAO          1,434,339             142,884      1,577,223       1,422,591     154,631           (769)        (6,288)      147,574
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         CPOP7          1,689,442             155,849      1,845,292       1,634,094     211,197        (13,968)         2,448       199,678
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         CPOP8          5,517,075             167,988      5,685,063       5,117,844     567,219            (45)      (217,446)      349,728
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         CSODW                688                    -            688             688            -            -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         FN086          1,233,220             146,323      1,379,544       1,243,365     136,178              -           (218)      135,961
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         GAF6G              1,183                    -          1,183           1,183            -            -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         GAF6P            429,757              46,171        475,927         475,855            73            -            (73)             -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         GAFH6            995,135             106,776      1,101,911       1,101,858            53            -            (53)             -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         GAG2E            550,596              55,966        606,562         606,458          104             -           (104)             -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         GAG2U            296,789              33,879        330,668         330,541          127             -           (127)             -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         GAG7F            226,639              24,752        251,391         251,199          192             -           (192)             -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         GAH2H            113,151              11,803        124,955         124,955             -            -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         GAJ2J            132,031              13,670        145,701         145,701             -            -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         GAJ2K            228,461              17,876        246,337         246,326            10            -            (10)             -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         GAJ3K            208,592              25,135        233,726         233,726             -            -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         SGG2D            755,995              87,575        843,570         842,847          723             -           (723)             -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         SU084          3,239,437             143,246      3,382,683       2,924,024     458,659           (373)        (3,967)      454,318
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         SU085                  -                    -              -               -            -            -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         SULSY          1,434,169             151,485      1,585,654       1,366,430     219,224          4,446          3,300       226,970
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         SUUOS             14,122                    -         14,122          12,175       1,947             -              -          1,947
                     UTILITY & EXECUTIVE MANAGEMENT              ESI         SUUS1            132,639                1,847       134,487         105,927       28,560             -           (141)       28,420

                     UTILITY & EXECUTIVE MANAGEMENT              Total ESI                  28,688,315        2,014,250     30,702,565     28,491,933       2,210,631       (39,503)     (231,900)     1,939,228

                     Total UTILITY & EXECUTIVE MANAGEMENT                                   28,688,315        2,014,250     30,702,565     28,491,933       2,210,631       (39,503)     (231,900)     1,939,228

                     Total for Witness Domino, Joe                                          28,688,315        2,014,250     30,702,565     28,491,933       2,210,631       (39,503)     (231,900)     1,939,228
3-45




                           Amounts may not add or tie to other schedules due to rounding.                                                                                                                              EXHIBIT JFD-A
                                                                                                                            Domino, Joe                                                                                   Page 1 of 1
    This page has been intentionally left blank.




2011 ETI Rate Case                       3-46
                                                                                                                                                                    ENTERGY TEXAS, INC.                                                                                                           EXHIBIT JFD-B
2011 ETI Rate Case




                                                                                                                                                     Affiliate Billings - by Witness, Class and Project                                                                                        2011 TX Rate Case
                                                                                                                                                       For the Twelve Months Ended June 30, 2011                                                                                                      Page 1 of 6
                                                                                                                                                                      Amounts in Dollars

                                                                                                                                                                              (A)               (B)           (C)              (D)          (E)           (F)          (G)           (H)
                                                                                                                                                                                           Total Billings
                                                                 Billing      Activity / Project                                                            ESI Billing                   Service Company                                  ETI Per                   Pro Forma     Total ETI
                                      Class                      Entity             Code                            Activity / Project Description           Method         Support          Recipient        Total       All Other BU's   Books       Exclusions     Amount       Adjusted
                     UTILITY & EXECUTIVE MANAGEMENT            ESI                                                                                                                 80                   -           80               80           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          C1PPFI5207             Payroll Time & Labor - Phase I                          EMPLOYAL               (25)                 (2)         (27)             (26)         (1)            0             1            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          C1PPFIRGTL             Regulated Time-LBR & Absence M                          EMPOPCPE             1,786                 246        2,032            1,853         179          (179)            -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          C1PPHR8800             PS HCM (Human Cap Mgmt) Upgrd                           EMPLOYAL                 (9)                (1)         (10)             (10)         (0)            0             0            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          C1PPSP0008             SPO ELL&ENOI Purchase Option I                          OWNISES2                  -                 (2)          (2)              (2)          -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          C5PC449602             GAS FAILURES BLANKET                                    DIRCTENO            35,953                   -       35,953           35,953           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          C5PP449606             Gas Serv Storm Rebuild Replace                          DIRCTENO           109,358              13,157      122,515          122,515           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          C6PCN32144             GRAND GULF EXTENDED POWER UPRA                          DIRCTSER               796                  96          892              892           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          C6PPAMBSGN             AMI:BASE Non-Incremental, EGSL                          DIRECTLG               (54)                 (7)         (61)             (61)          -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          C6PPSP0012             SPO Project Gator Transact/Tra                          DIRCTELI               834                  95          928              928           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          C6PPWGP516             SBC CIP Compliance                                      DIRECTTX            12,289               1,679       13,968                -      13,968       (13,968)            -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          C6PPWS0534             System Planning Pet Coke Repow                          DIRCTELI               274                  31          305              305           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          C6PPWS0783             Ninemile 6 Development                                  DIRCTELI             8,423               1,072        9,495            9,495           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          C7PPSJ1214             WINTER STORM DL EAI DIST 01/26                          DIRCTEAI                  -                  -            -                -           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          C7PPSJ1244             STORM DL ARK DIST EAI 1/7/11 I                          DIRCTEAI                98                  13          111              111           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          C7PPSJ1250             STORM DL EAI DIST 4/19/11-4/24                          DIRCTEAI             2,890                 433        3,323            3,323           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          C7PPSJ1251             TORNADOES DL EAI DIST 4/25/11                           DIRCTEAI             5,554                 861        6,416            6,416           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          C7PPSJ2462             STORM DMG LA DIST ELL 1/8/11 I                          DIRCTELI             1,575                 260        1,835            1,835           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          C7PPSJ2474             STORM Dmg ELL 4/25 to 4/27/11                           DIRCTELI               100                  12          112              112           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          C7PPSJ3183             EMI 04/24/10 Tornadoes Distr O                          DIRCTEMI                  -                  -            -                -           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          C7PPSJ3198             EMI Storm Distr Ops 1/7/11Wint                          DIRCTEMI            20,268               2,733       23,001           23,001           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          C7PPSJ3204             EMI StormTornadoes DistrOps 4/                          DIRCTEMI               100                  12          112              112           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          C8PPTL5496             Replace Storm Damages                                   DIRCTEAI            20,682               3,097       23,779           23,779           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          E1PCD10064             DISTR WK MGMT-SUBST AOR/COS/SF                          CUSEOPCO                  1                  0            1                1           0             -             0            0
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          E1PCR56025             CUSTOM SALES & SERVICE UNIT- M                          DIRCTELI               688                   -          688              688           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          E1PCR56226             Sales & Mktg - ALL JURIS                                MACCTALL             8,492                 956        9,448            8,222       1,226             -           (23)       1,202
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          E1PPNXCRP1             Unwind - Employee                                       DIRECTNI            21,844               3,253       25,096           25,096           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          E2PPLG11DA             Logistics Jan 2011 DIST Ark                             DIRCTEAI                  0                 (2)          (2)              (2)          -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          E2PPLG11DL             Logistics Jan 2011 DIST ELL                             DIRCTELI                  0                (15)         (15)             (15)          -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          E2PPLG11DM             Logistics Jan 2011 DIST Miss                            DIRCTEMI                  0                (25)         (25)             (25)          -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          E2PPLG11TL             Logistics Jan 2011 TRN ELL                              DIRCTELI                  -                 (0)          (0)              (0)          -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          E2PPLG11TM             Logistics Jan 2011 TRN Miss                             DIRCTEMI                  -                 (1)          (1)              (1)          -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          E2PPSJ1255             T-Grid Storm Tornadoes EAI 4/2                          DIRCTEAI               315                  44          359              359           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          E2PPSJ2447             T-Grid Storm O&M ELL 1/7/201 I                          DIRCTELI                11                   2           13               13           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          E2PPSJ3188             T-Grid Storm Damage EMI 1/7/11                          DIRCTEMI                28                   4           31               31           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PC6H0026             NORTHEAST MGMT OVERSITE IP2/IP                          SPL77N7A            24,988                   -       24,988           24,988           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PC6HENNE             ENN EQUAL SPLIT                                         DIRCTENU               588                   -          588              588           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCC08500             Executive VP, Operations                                ASSTSALL            17,701                 951       18,652           16,787       1,864             -           (96)       1,768
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCC14900             EXPENSES-CHAIRMAN ENTERGY                               DIRCTETR           448,364              56,234      504,599          504,599           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCC31255             OPERATIONS-OFFICE OF THE CEO                            ASSTSALL         3,036,304             193,032    3,229,335        2,909,321     320,015          (645)       (4,828)     314,542
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCC31256             LEADERSHIP CONFERENCE                                   EMPLOYAL           186,861                   -      186,861          178,151       8,711             -             -        8,711
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCC31257             EVENTS ADMINISTRATION                                   DIRCTETR           826,330                   -      826,330          826,330           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCCDVCCN             PROJECT GUMBO                                           CUSGOPCO                  -                  -            -                -           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCCDVETR             CORP DEV-ANALYSIS STRATEGIC ME                          ASSTSALL                  -                  -            -                -           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCCE0155             BELOW THE LINE-C ENVIRONMENTAL                          CAPAOPCO                  -                  -            -                -           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCCEP001             CORPORATE ENVIRONMENTAL POLICY                          CAPAOPCO         2,196,785                   -    2,196,785        1,959,288     237,496             -             -      237,496
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCCPM001             CORPORATE PERFORMANCE MANAGEME                          ASSTSALL         1,197,217             142,793    1,340,010        1,207,839     132,171             -           (68)     132,103
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCCSE060             SAFETY & ENVIRONMENTAL SUPPORT                          EMPLOYAL               747                  62          810              770          40             -             1           41
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCCSPUTI             SYSTEM PLANNING & STRATEGIC AD                          LOADOPCO            27,668               3,370       31,038           26,324       4,714             -            98        4,811
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCD10006             FIELD DEVELOPMENT                                       CUSTEGOP                  6                  1            7                6           1             -             0            1
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCD10010             PROGRAM MANAGEMENT - O&M                                CUSTEGOP                  9                  1           10                8           1             -             0            1
3-47




                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCD10033             SSS PRELIMINARY PLANNING, SCOP                          CUSTEGOP                  0                  0            0                0           0             -             0            0
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCD10049             REGULATED RETAIL SYSTEMS - O&M                          CUSTEGOP                25                   3           28               24           4             -             0            4
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCD10077             REGULATORY AFFAIRS WORLDOX IMP                          DIRCTENO                  4                  1            5                5           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCD10105             CUSTOMER CARE SYSTEM SUPPORT                            CUSEGXTX                83                  10           93               93           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCDG0004             OPERATOR QUAL DEVELOP & TRAIN                           DIRCTENO            27,119               2,217       29,336           29,336           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCDG0005             OPERATOR QUAL DEVELOP & TRAIN                           DIRECTLG            89,501               8,908       98,409           98,409           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCE13100             GEN CORP. LEGAL ENTERGY CORP.                           DIRCTETR             3,792                 552        4,344            4,344           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCE13321             ESI GENERAL LEGAL ADVICE                                LVLSVCAL             3,792                 552        4,344            3,931         413             -             8          421
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCE14420             REGULATORY AFFAIRS - EAI                                DIRCTEAI                26                   -           26               26           -             -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCE14987             FGA-Climate/Environmental                               ASSTSALL            47,580                   -       47,580           42,787       4,793        (4,793)            -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCE99741             Utl Ops ECI & 6-Sigma Improve                           CUSEOPCO               249                   -          249              212          37             -             -           37

                           Amounts may not add or tie to other schedules due to rounding.                                                                                                                                                                                                         EXHIBIT JFD-B
                                                                                                                                                                          Domino, Joe                                                                                                                Page 1 of 6
                                                                                                                                                                   ENTERGY TEXAS, INC.                                                                                                           EXHIBIT JFD-B
2011 ETI Rate Case




                                                                                                                                                    Affiliate Billings - by Witness, Class and Project                                                                                        2011 TX Rate Case
                                                                                                                                                      For the Twelve Months Ended June 30, 2011                                                                                                      Page 2 of 6
                                                                                                                                                                     Amounts in Dollars

                                                                                                                                                                              (A)             (B)          (C)              (D)          (E)          (F)             (G)           (H)
                                                                                                                                                                                         Total Billings
                                                                 Billing      Activity / Project                                                            ESI Billing                 Service Company                                 ETI Per                     Pro Forma     Total ETI
                                      Class                      Entity             Code                           Activity / Project Description            Method         Support        Recipient       Total       All Other BU's   Books      Exclusions        Amount       Adjusted
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCE99750             PRES- ENT. LA-GEN'L OPS-ELI/EG                         CUSELGLA          1,114,809            70,756   1,185,564        1,185,564           -               -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCE99751             SPECIAL PROJECTS - LA STATE PR                         CUSELGLA                 71                 -           71              71           -               -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCE99795             GROUP PRES - UTILITY OPERATION                         CUSTEGOP          2,011,555           130,481   2,142,037        1,845,705     296,332            (373)       (3,718)     292,241
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF07300             CORP PLANNING & ANALYSIS- REGU                         CUSTEGOP             10,104             1,234      11,338            9,775       1,563               -            31        1,595
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF10414             ESI TAX SERVICES                                       LVLSVCAL                 24                 3           27              24           3               -             0            3
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF10445             ENTERGY CONSOLIDATED TAX SERVI                         ASSTSALL                  2                 0            2               2           0               -             0            0
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF15260             IT - BUSINESS & PROJECT SUPPOR                         CAPAOPCO                  5                 1            5               5           1               -             0            1
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF21600             CORP RPTG ANALYSIS & POLICY AL                         GENLEDAL              4,616               418       5,035            4,717         317               -             7          324
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF22511             IR - GENERAL, INQUIRIES & MAIL                         DIRCTETR                404                 -          404             404           -               -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF22514             MEETINGS ANALYSTS/INVESTORS/SH                         DIRCTETR              5,306                 -       5,306            5,306           -               -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF23033             GENERAL ACCOUNTING - ESI                               LVLSVCAL                977               135       1,112            1,007         105               -             2          107
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF23425             ACCOUNTS PAYABLE PROCESSING                            APTRNALL                190                17          207             188          19               -             0           19
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF23428             TREASURY SYSTEMS                                       BNKACCTA                 69                 8           77              75           2               -             0            2
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF23442             PAYROLL PROCESSING                                     PRCHKALL                 89                 8           98              93           5               -             0            5
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF23920             CORP REPORTING ANALYSIS & POLI                         DIRCTELI             32,744             3,899      36,643           36,643           -               -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF239LA             CORP RPTNG ANALYSIS/POLICY EGS                         DIRECTLG             32,690             3,893      36,583           36,583           -               -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF24910             PROPERTY ACCOUNTING- FIXED ASS                         ASSTLOCA                 59                 7           67              60           7               -             0            7
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF26910             REVENUE ACCOUNTING ANALYSIS                            CUSEGALL                 40                 5           45              38           6               -             0            6
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF72271             DATA WAREHOUSE                                         GENLEDAL                 67                 6           74              69           4               -             0            4
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF72670             GENERAL ACCOUNTING SYSTEM MAIN                         GENLEDAL                823                76          899             847          52               -             1           53
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF72901             MOBILE DATA TERMINAL BASELOAD                          CUSTEGOP                  5                 1            6               5           1               -             0            1
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF73027             BUDGET SYSTEM MAINTENANCE                              GENLEDAL                153                14          168             158          10               -             0           10
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF73901             AM/FM BASELOAD (SUPPORT)                               DIRECTTX                  3                 0            3               -           3               -             0            3
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF74195             TRANSMISSION APPLICATION SUPPO                         TRSBLNOP                161                19          180             159          21               -             0           22
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF74341             ISB MAINT                                              LOADWEPI                  5                 1            5               5           1               -             0            1
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF74344             GENERATION PLANNING & DISPATCH                         LOADOPCO                 20                 2           22              19           3               -             0            3
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF74515             FOSSIL MAINTENANCE MANAGEMENT                          CAPAOPCO                 40                 5           45              40           5               -             0            5
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF74585             FOSSIL APPLICATION SUPPORT                             CAPAOPCO                 43                 5           48              42           5               -             0            5
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCF99182             RECORDS MANAGEMENT                                     RECDMGNT                 11                 1           12              10           1               -             0            1
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFACALL             FACILITIES SVCS- ALL COS                               SQFTALLC              9,149               282       9,431            8,386       1,045             (73)         (436)         536
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFAPWHS             POWERHOUSE OPERATIONS                                  EMPLOYAL                123                 -          123             117           6               -            (6)           -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFBLREG             BELOW THE LINE- REGULATED                              CUSTEGOP                  -                 -            -               -           -               -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFCPO01             CHIEF PROCUREMENT OFFICER                              SCPSPALL              8,175               980       9,155            8,049       1,106               -            23        1,128
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFCQEAI             ENTERPRISE APPLICATION INTEGRA                         APPSUPAL                292                32          323             274          49               -             1           50
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFCQEXC             EXCHANGE                                               PCNUMALL                312                26          338             325          13               -             0           14
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFCQMVS             MAINFRAME                                              APPSMVSX                  -                 -            -               -           -               -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFCQNTS             NT SERVERS                                             APPSWINT                  -                 -            -               -           -               -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFCQUNX             UNIX SERVERS                                           APPSUNIX                  -                 -            -               -           -               -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFEXETR             EXECUTIVE ADVISORY SERVICES -                          DIRCTETR             44,620             5,822      50,442           50,442           -               -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFX2770             HR SERVICE CENTER SUPPORT                              EMPLOYAL                  -                 -            -               -           -               -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFX2815             EDMS PRODUCT LINE SUPPORT                              EMPLOYAL                 60                 6           66              63           3               -             0            3
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFX2850             SECRETARIAT LEGAL SUPPORT                              ASSTSALL                  4                 0            5               4           1               -             0            1
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFX3265             POWERBUILDER FRAMEWORK BASELOA                         APPSUPAL                  5                 0            5               4           1               -             0            1
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFX3275             WEB INFRASTRUCTURE MAINTENANCE                         PCNUMALL                  9                 1           10               9           0               -             0            0
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFX3290             IT BUSINESS PLANNING AND GOVER                         ITSPENDA              3,818               470       4,288            4,002         285               -             6          291
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFX3350             A/R & BILLING SUPPORT                                  ARTRNALL                 72                 8           80              71           9               -             0            9
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFX3355             Property Software Support                              GENLEDAL                  3                 0            3               3           0               -             0            0
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFX3450             CORPORATE REPORTING SYSTEM SUP                         GENLEDAL                  0                 -            0               0           -               -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFX3620             MMIS MATERIALS MAINT MGMNT INF                         DIRCTESI                  0                 -            0               0           -               -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFX3625             SUPPLY CHAIN - CDW SYSTEMS SUP                         SCDSPALL                  4                 0            4               3           2               -             0            2
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFX3640             WHITE AMBER & ITILITI SUPPORT                          SCMATRAN                  -                 -            -               -           -               -             -            -
3-48




                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFX3650             WEB PAGE SUPPORT - CORPORATE                           EMPLOYAL                  1                 0            1               1           0               -             0            0
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFX3670             CORPORATE COMMUNICATIONS WEB S                         DIRCTETR                  4                 0            4               4           -               -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFX3675             BARCODING SYSTEMS SUPPORT                              SCDSPALL                  2                 0            2               1           1               -             0            1
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFX3690             PEARL SUPPORT                                          APTRNALL                  1                 0            1               1           0               -             0            0
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFX3695             ATPR SUPPORT                                           APTRNALL                 61                 6           67              61           6               -             0            6
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFX3785             ORG, JES, BATS, ACBM SUPPORT                           GENLEDAL                  0                 -            0               0           -               -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFX3790             ESTER SUPPORT                                          PRCHKALL                 96                 9          105              99           5               -             0            5
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCFX5555             DATA WAREHOUSE TOOLS SUPPORT                           APPSUPAL                 25                 3           28              24           4               -             0            4
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCG10345             GAS DIVISION DIRECTOR - ENOI E                         DIRCTENO            686,476            70,426     756,902          756,902           -               -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCG10347             GAS DIVISION DIRECTOR - EGSI E                         DIRECTLG            552,734            57,006     609,740          609,740           -               -             -            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCH60959             EXECUTIVE FACILITIES SERVICES                          DIRCTETR                348                 -          348             348           -               -             -            -

                           Amounts may not add or tie to other schedules due to rounding.                                                                                                                                                                                                        EXHIBIT JFD-B
                                                                                                                                                                          Domino, Joe                                                                                                               Page 2 of 6
                                                                                                                                                                    ENTERGY TEXAS, INC.                                                                                                            EXHIBIT JFD-B
2011 ETI Rate Case




                                                                                                                                                     Affiliate Billings - by Witness, Class and Project                                                                                         2011 TX Rate Case
                                                                                                                                                       For the Twelve Months Ended June 30, 2011                                                                                                       Page 3 of 6
                                                                                                                                                                      Amounts in Dollars

                                                                                                                                                                               (A)             (B)          (C)             (D)          (E)           (F)            (G)           (H)
                                                                                                                                                                                          Total Billings
                                                                 Billing      Activity / Project                                                             ESI Billing                 Service Company                                ETI Per                     Pro Forma     Total ETI
                                      Class                      Entity             Code                            Activity / Project Description            Method         Support        Recipient       Total      All Other BU's   Books       Exclusions       Amount       Adjusted
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCHRCALL             HR SVCS- CUST SERV SUPT- ALL C                          EMPLOCSS                196                 -         196             181           15              -             -            15
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCHRDCSS             HR- FRANCHISE OPNS (DIST) SUPT                          EMPLFRAN                481                 -         481             414           66              -             -            66
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCHRFOSS             HR FOSSIL SUPPORT- ALL COS                              EMPLOFOS                537                 -         537             488           48              -             -            48
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCHRPRES             HR PRESIDENT/ CEO SUPPORT- ALL                          EMPLPRES                  7                 -           7               6            1              -             -              1
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCHRSALL             HR SERVICES- ALL COMPANIES                              EMPLOYAL            317,117            33,482     350,598         333,715       16,883              -           (72)       16,812
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCHRSDUT             HR SVCS - ESI DOMESTIC UTILITY                          DIRCTESI                  8                 -           8               8            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCHRTRAN             HUMAN RESOURCE SVCS - TRANSMIS                          EMPLTRAN                115                 -         115             106            9              -             -              9
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCMCMSOM             MATERIALS & CONTRACTS MGTMT SY                          SCMATXNU                  -                 -           -               -            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCN20520             WORK MANAGEMENT SYSTEM (WMS) M                          DIRCTEOI                 25                 3          28              28            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCN20521             IDEAS MAINTENANCE                                       DIRCTEOI                 76                 9          86              86            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCN20522             PCRS MAINTENANCE                                        DIRCTEOI                133                16         149             149            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCN20527             NUCLEAR IT QUICK RESPONSE TEAM                          DIRCTEOI                 44                 5          49              49            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCN20528             ERD SUPPORT (MAINTENANCE)                               DIRCTEOI                617                74         691             691            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCN20858             NUCLEAR IT QUICK RESPONSE TEAM                          DIRCTEOI                  2                 0           3               3            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCR40085             ENTERGY CORPORATION COMMUNICAT                          DIRCTETR             10,500                 -      10,500          10,500            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCR40118             UTILITY COMMUNICATIONS                                  CUSTEGOP             83,560                 -      83,560          72,040       11,521              -          (118)       11,403
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCR40430             EMPLOYEE COMM (REGULATED COMPA                          EMPLOREG             71,944                 -      71,944          67,408        4,535              -             -         4,535
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCR40500             EMPLOYEE COMM (REG + UNREG COM                          EMPLOYAL                  4                 0           5               5            0              -             0              0
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCR53095             HEADQUARTER'S CREDIT & COLLECT                          CUSTEGOP                  0                 -           0               0            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCR53291             ESI REMITTANCE PROCESSING                               CUSEOPCO                151                18         170             145           25              -             1            26
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCR73326             CUSTOMER SERVICE CENTER SUPPOR                          CUSTCALL                130                16         146             130           16              -             0            16
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCR73380             CREDIT SYSTEMS                                          CUSTEGOP                 40                 5          44              38            6              -             0              6
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCR93300             NORTHEAST NONREG NUCLEAR EXTRN                          DIRCTENU                  -                 -           -               -            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCRM1021             AUDIT: ESI INFORMATION TECHNO                           DIRCTESI                  3                 -           3               3            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCSYSAGR             SYSTEM AGREEMENT-2001                                   CUSEOPCO            771,530                96     771,625         657,743     113,883               -             4      113,887
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCSYSRAS             SYSTEM REGULATORY AFFAIRS-STAT                          CUSTEGOP            105,291                 8     105,299          90,781       14,518              -           (10)       14,508
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCT29320             SKILLS TRAINING CUST. SERV- HE                          CUSEOPCO                163                 -         163             139           24              -             -            24
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCT29400             OPERATIONS SAFETY - HEADQUARTE                          CUSTEGOP            689,509            74,343     763,852         658,206     105,647             512         1,807      107,966
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCT29406             OPERATIONS SAFETY - TEXAS DIST                          DIRECTTX             15,773                 -      15,773               -       15,773              -             -        15,773
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCT54052             Trans Regulatory Support/Polic                          TRSBLNOP              9,442               868      10,310           9,099        1,211              -            24         1,235
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCT54065             OPNS OF PURCHASING & CONT-DCS                           SCMATRAN                  0                 0           0               0            0              -             0              0
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCTBLLPL             BELOW THE LINE - LPL                                    DIRCTELI                  -                 -           -               -            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCTDDS26             CUSTOMER SERVICE SUPPORT - O&M                          CUSTEGOP                120                 -         120             103           17              -             -            17
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCTDPQ01             DISTR POWER QUALITY ESI                                 CUSEOPCO                  3                 0           3               2            0              -             0              0
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCTDS010             PROCESS & SKILLS TRAINING ADMI                          EMPLFRAN            120,567            14,007     134,574         115,628       18,946              -           389        19,335
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCTDTR08             SKILLS TRAINING - LOUISIANA EL                          DIRCTELI                  -                 -           -               -            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCTTDS12             TRANSMISSION LINES O&M EXPENS                           TRALINOP                  -                 -           -               -            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCTTDS17             Substation Maintenance EGSI LA                          DIRECTLG              1,540                 -       1,540           1,540            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCTTDS19             SUBSTATION/SYSTEM PROT MAINT -                          DIRCTEAI             10,322                 -      10,322          10,322            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCTTDS21             SUBSTATION/SYSTEM PROT MAINT -                          DIRCTELI              1,540                 -       1,540           1,540            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCTTDS22             SUBSTATION/SYSTEM PROT MAINT -                          DIRCTEMI              7,620                 -       7,620           7,620            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCTTDS23             Substation Maintenance - Texas                          DIRECTTX             15,773                 -      15,773               -       15,773              -             -        15,773
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCTTDS24             SUBSTATION/SYSTEM PROT MAINT -                          DIRCTENO              1,540                 -       1,540           1,540            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCTTDS27             DISTRIBUTION O&M EXPENSE -EAI                           DIRCTEAI             13,605                 -      13,605          13,605            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCTTDS28             DISTRIBUTION O&M EXPENSE -EMI                           DIRCTEMI             11,088               376      11,464          11,464            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCTTDS29             DISTRIBUTION O&M EXPENSE -ELI                           DIRCTELI              9,001               708       9,709           9,709            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCTTDS30             DISTRIBUTION O&M EXPENSE -EGSI                          DIRECTLG              1,540                 -       1,540           1,540            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCTTDS31             DISTRIBUTION O&M EXPENSE - ENO                          DIRCTENO              1,596                 -       1,596           1,596            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCTTDS38             TRANSMISSION O&M MGMT/SUPPORT                           TRSBLNOP          1,871,582             4,636   1,876,218       1,655,755     220,463             (17)           90      220,536
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCTTDS46             DISTRIBUTION O&M EXP - METRO E                          CUSEMETR                159                 -         159             159            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCTTDS47             DISTR O&M EXPENSE - LOUISIANA                           CUSTELLA                943                 -         943             943            -              -             -              -
3-49




                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCTTDS71             TRANSMISSION MANAGEMENT/SUPPOR                          DIRCTEAI                  -                 -           -               -            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCW29607             POWER SYSTEM ACCOUNTING                                 LOADWEPI                  3                 0           4               3            1              -             0              1
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCW29608             TRANSMISSION POWER SYSTEM OPER                          LOADOPCO              6,950               639       7,589           6,456        1,133              -            22         1,155
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCW55555             VP FOSSIL GENERATION                                    CAPAOPCO             14,414             1,850      16,265          14,506        1,758              -            32         1,791
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCWE0063             EMO APPLICATION SUPPORT                                 LOADOPCO                 17                 2          19              16            3              -             0              3
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCWE0073             FOSSIL INFORMATION TECHNOLOGY                           CAPAOPCO                  3                 0           3               3            0              -             0              0
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCWE0135             NEL. 6 JOINT OWNERSHIP PART. A                          DIRECTLG                964               108       1,072           1,072            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCWE0187             FOSSIL IT SUPPORT FOR 2003-200                          CAPAOPCO                  -                 -           -               -            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCWS0327             SAIC LABOR CHARGES TO PMDC                              CAPAOPCO                 53                 6          60              53            7              -             0              7
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCZGASAG             GAS ADMINISTRATIVE                                      CUSGOPCO          1,119,964           119,476   1,239,440       1,239,440            -              -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCZU1603             LP&L/LPSC EARNINGS REVIEW; DOC                          DIRCTELI              2,335               298       2,633           2,633            -              -             -              -

                           Amounts may not add or tie to other schedules due to rounding.                                                                                                                                                                                                          EXHIBIT JFD-B
                                                                                                                                                                           Domino, Joe                                                                                                                Page 3 of 6
                                                                                                                                                                     ENTERGY TEXAS, INC.                                                                                                                EXHIBIT JFD-B
2011 ETI Rate Case




                                                                                                                                                      Affiliate Billings - by Witness, Class and Project                                                                                             2011 TX Rate Case
                                                                                                                                                        For the Twelve Months Ended June 30, 2011                                                                                                           Page 4 of 6
                                                                                                                                                                       Amounts in Dollars

                                                                                                                                                                                (A)              (B)           (C)            (D)          (E)            (F)              (G)           (H)
                                                                                                                                                                                            Total Billings
                                                                 Billing      Activity / Project                                                              ESI Billing                  Service Company                                ETI Per                       Pro Forma      Total ETI
                                      Class                      Entity             Code                             Activity / Project Description            Method         Support         Recipient        Total     All Other BU's   Books        Exclusions        Amount        Adjusted
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PP1E2EPM             End-to-End Process Mgmnt                                 LVLSVCAL              3,230                407        3,637          3,291          347                -              7           354
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PP4R9886             TRITIUM DETECTION INVESTIGATIO                           DIRECT72             23,182              2,309       25,491         25,491            -                -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PP6HHOST             ENNE Hosting/server support/SO                           DIRCTENU                135                 16           151           151            -                -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PP6HINDS             Indus Passport                                           DIRCTENU                339                 41           379           379            -                -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPAMISTG             AMI Strategy Expense                                     CUSEOPCO                223                 27           250           213           37                -              1            38
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPAMPDEV             Advanced Mgmt Dev Program                                EMPLOYAL              4,112                  -        4,112          3,921          192                -           (192)             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPBLANCO             Project White                                            DIRCTETR             38,891              5,003       43,894         43,894            -                -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPC31258             CEO MEETINGS WITH EMPLOYEES                              EMPLOYAL                350                  -           350           334           16                -              -            16
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPCAO001             Chief Administrative Officer                             ASSTSALL          1,431,497            145,499    1,576,996      1,421,598     155,398              (769)        (6,899)     147,730
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPCCS010             Climate Consulting Services                              ASSTSALL            289,337             31,693      321,030        289,415       31,615                -            547        32,162
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPCOO001             CHIEF OPERATING OFFICER                                  ASSTSALL            582,384             63,085      645,469        581,811       63,658               (3)        (2,115)       61,540
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPCPMUTL             CORPORATE PERFORMANCE MGMT UTL                           EMPXRTNC             19,531              1,594       21,126         19,133        1,992                -             40         2,032
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPD10115             Dist Work Mgmt O&M-DIS/DSS/ADS                           CUSTEGOP                176                 21           197           170           27                -              1            28
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPD10116             Dist Work Mgmt O&M-LAMP Street                           CUSEOPCO                  1                  0             1             1            0                -              0              0
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPD10119             Dist Work Mgmt O&M-CTS Contrac                           CUSTEGOP                 23                  3            26            22            4                -              0              4
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPD10120             Dist Oper Appl O&M-AM/FM Suppo                           CUSTEGOP                269                 32           302           260           42                -              1            42
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPD10121             Dist Oper Appl O&M-AutoCAD                               CUSEOPCO                 12                  1            14            12            2                -              0              2
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPD10123             Dist Oper Appl O&M-EPO&SAISO S                           CUSEOPCO                 21                  3            24            20            4                -              0              4
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPD10124             Dist Oper Appl O&M-PDD/ECOS Sp                           CUSTEGOP                  8                  1             9             8            1                -              0              1
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPD10128             ARCS/Itron/MV90 Support                                  CUSTEGOP                 73                  9            82            71           11                -              0            12
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPD10129             Billing Determinate Proc/Major                           CUSTEGOP                 56                  7            62            54            9                -              0              9
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPD10130             Customer Care System Interface                           CUSEGXTX                 98                 12           109           109            -                -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPD10131             CIS/AIS & Core Support                                   DIRECTTX                805                 97           902             -          902                -             19           921
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPD10132             Electronic Data Interchange Su                           CUSEOPCO                 20                  2            23            19            3                -              0              3
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPD10133             Internet Bill Presentment & Pm                           CUSEGXTX                 15                  2            17            17            -                -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPD10134             MAB Load Research Support                                CUSTEGOP                 19                  2            22            19            3                -              0              3
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPD10137             Bill Delivery Support                                    CUSEGXTX                482                 58           539           539            -                -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPD10139             Mobius Support                                           CUSTEGOP                  0                  0             0             0            0                -              0              0
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPD10140             Large Power Billing System for                           CUSEOPCO                 23                  3            25            22            4                -              0              4
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPD10141             CIMS Support                                             CUSEGXTX                  2                  0             2             2            -                -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPD10142             Customer Service Field Applica                           CUSTEGOP                 11                  1            12            10            2                -              0              2
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPD10146             Dist Work Mgmt-Cyndrus Support                           VEHCLALL                  8                  1             9             8            1                -              0              1
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPD10150             TaxWare Support                                          CUSTEGOP                 50                  6            56            48            8                -              0              8
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPD10158             CCS Agent Care System                                    CUSEGXTX                 46                  6            52            52            -                -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPD10161             ePlus (Web Self Service) Suppo                           CUSTEGOP                146                 17           163           141           22                -              0            23
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPE9974S             Utl ECI Continuing Improve ESI                           CUSEOPCO            233,026             23,604      256,630        218,728       37,902                -            387        38,289
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPE9981A             Integrated Energy Mgmt EAI                               DIRCTEAI                  -                  -             -             -            -                -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPE9981S             Integrated Energy Mgmt ESI                               CUSEOPCO             15,986              1,847       17,834         15,206        2,628                -              8         2,636
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPEGSFRP             EGSI LPSC Formula Rate Plan Fi                           DIRECTLG                686                 77           763           763            -                -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPELEGAS             ENO Elec & ENO EGS Gas Expense                           CUSENLGG             (9,627)            (2,615)     (12,242)       (12,242)           -                -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPENOCEO             ENO CEO Electric and Gas Expen                           DIRCTENO                  -                  -             -             -            -                -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPENOFRP             ENO Annual FRP Filing 2010-12                            DIRCTENO              2,739                312        3,051          3,051            -                -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPEPI001             Environmental Programs & Infra                           CAPAOPCO               (179)                 -         (179)          (160)         (19)               -             (1)          (20)
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPETEGSL             Executive Timesheets- EGSL                               DIRECTLG              2,215                216        2,430          2,430            -                -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPETENOI             Executive Timesheet- ENOI                                DIRCTENO             61,975              1,967       63,943         63,943            -                -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPETRNUC             Executive Timesheets- Reg Nuc                            DIRCTEOI             17,530              1,880       19,410         19,410            -                -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPETSEAI             Executives Time and Expenses-E                           DIRCTEAI             35,047              3,609       38,656         38,656            -                -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPETSELI             Executive Timesheets- ELI                                DIRCTELI             83,570              2,603       86,173         86,173            -                -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPETSEMI             Executive Timesheets- EMI                                DIRCTEMI             17,613              1,500       19,113         19,113            -                -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPETSETI             Executive Time and Expenses-ET                           DIRECTTX             36,090              3,510       39,601              -       39,601                -            765        40,365
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPETSETR             Executive Timesheets-ETR                                 DIRCTETR            737,895             97,043      834,938        834,938            -                -              -              -
3-50




                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPETSNRG             Executive Timesheets- Non Reg                            DIRCTENU             10,307                595       10,902         10,902            -                -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPETSREG             Executive Timesheets- Reg Co's                           CUSTEGOP             12,783                865       13,648         11,767        1,882                -             29         1,911
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPF15115             FGA-VP/General Office                                    CUSTEGOP                199                  -           199           171           28              (28)             -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPF72700             Cognos Reporting Support                                 GENLEDAL                 22                  2            24            23            1                -              0              1
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPFRM127             OCRO - Bus Cont Plan Managemen                           LBRBILAL                  -                  -             -             -            -                -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPFX3259             Inventory Planning System Supp                           SCTDSPAL                 34                  4            38            25           12                -              0            13
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPFX3685             Supply Chain Applications Supp                           SCMATRAN                 61                  7            68            58           10                -              0            10
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPFX5307             Compliance Software System Sup                           ASSTSALL                 38                  5            42            38            4                -              0              4
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPFXOPMO             IT Enterprise Program Manageme                           ITSPENDA                 22                  2            25            23            2                -              0              2
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPGRSP10             EGSL RATE STABLIZATN (TY 2009/                           DIRECTLG                 88                 10            98            98            -                -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPHIPPO1             Project X                                                DIRCTETR             34,735              5,181       39,916         39,916            -                -              -              -

                           Amounts may not add or tie to other schedules due to rounding.                                                                                                                                                                                                               EXHIBIT JFD-B
                                                                                                                                                                            Domino, Joe                                                                                                                    Page 4 of 6
                                                                                                                                                                      ENTERGY TEXAS, INC.                                                                                                           EXHIBIT JFD-B
2011 ETI Rate Case




                                                                                                                                                       Affiliate Billings - by Witness, Class and Project                                                                                        2011 TX Rate Case
                                                                                                                                                         For the Twelve Months Ended June 30, 2011                                                                                                      Page 5 of 6
                                                                                                                                                                        Amounts in Dollars

                                                                                                                                                                                 (A)              (B)          (C)              (D)          (E)          (F)          (G)           (H)
                                                                                                                                                                                             Total Billings
                                                                 Billing      Activity / Project                                                               ESI Billing                  Service Company                                 ETI Per                  Pro Forma     Total ETI
                                      Class                      Entity             Code                              Activity / Project Description            Method         Support         Recipient       Total       All Other BU's   Books      Exclusions     Amount       Adjusted
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPHRSSPC             HR SVS - ESI SUPPLY CHAIN                                 DIRCTESI                 18                  -          18               18           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPHRTFMN             HR Transformation - O&M Costs                             EMPLOYAL             91,155              9,889     101,043           96,167       4,877            -           100         4,976
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPN20535             P3E Scheduling Software Mainte                            DIRCTEOI                162                 19         182              182           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPN20536             INDUS Software Maintenance                                DIRCTEOI                288                 34         322              322           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPN20713             ESI Nuclear - Site Split                                  SNUCSITE             81,152             10,163      91,314           91,314           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPNPM008             Wholesale C B 50/50 Split - Pi                            DIRNG000                  -                  -           -                -           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPNXRECR             Enexus Recurring                                          DIRECTNI             (2,989)                 -      (2,989)          (2,989)          -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPPCS001             Critical Infrastructure Protec                            CAPAOPCO          1,644,835            151,796   1,796,631        1,602,395     194,236            -         2,391       196,626
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPPGA010             PGA Audit 2010                                            DIRECTLG                430                 50         480              480           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPPMUPGR             Performance Management Sys Upg                            CUSEOPCO                  3                  0           4                3           1            -             0             1
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPRC2008             ENOI 2008 RATE CASE                                       DIRCTENO                  -                  -           -                -           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPRES001             Regulated Utility Electric Rel                            CUSEOPCO              1,993                223       2,216            1,889         327            -             7           333
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPSCOUT1             Project Scout (VY Litigation A                            DIRECT72                 15                  -          15               15           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPSPE003             SPO Summer 2009 RFP Expense                               LOADOPCO              2,871                350       3,221            2,740         481            -            10           491
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPSPE042             SPO Expense ISES Purchase Opti                            OWNISES2                543                 70         614              614           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPTDERSD             MISO Transition ALL OPCO                                  LOADOPCO                905                111       1,016              847         169            -          (169)            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PCTTDS38             TRANSMISSION O&M MGMT/SUPPORT                             TRSBLNOP                  -                  -           -                -           -            -      (215,886)     (215,886)
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPWCBEAM             Wholesale Commodity Business -                            DIRECTXU             56,322              6,557      62,878           62,878           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPWCBEPM             Wholesale Commodity Business -                            DIRNG000                350                  -         350              350           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPWCBETC             Wholesale Commodity Business -                            DIRECT66             56,322              6,557      62,879           62,879           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPWCBNNE             Wholesale Commodity Business -                            SENUCALL            994,973             80,212   1,075,184        1,075,184           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPWE0292             System Planning Asset Manageme                            LOADOPCO                278                 38         316              263          52            -             1            53
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPWE0375             SAIC Designated Srv for Fossil                            CAPAOPCO                 10                  1          11               10           1            -             0             1
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPWE0504             M0000 - CIP Walkdown                                      DIRCTEMI              2,970                209       3,179            3,179           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPWE0505             N0000 - CIP Walkdown                                      DIRCTENO              2,404                213       2,617            2,617           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPWE0506             A0000 - CIP Walkdown                                      DIRCTEAI                825                  -         825              825           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPWE0507             L0000 - CIP Walkdown                                      DIRCTELI              5,220                481       5,701            5,701           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F3PPWEOSGN             General System-ENG-Tech Suppor                            CAPAOPCO              1,102                 80       1,182            1,054         128            -             1           129
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F4PPEGS148             Mutual Assist EGSL GAS NMGC 2/                            DIRECTLG                829                100         929              929           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F4PPENG134             Mutual Assist ENOI Gas NMGC 2/                            DIRCTENO                966                117       1,083            1,083           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCD10093             WEB DEVELOPMENT SUPPORT                                   CUSTEGOP                 15                  2          17               15           2            -             0             2
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCD10108             CCS REMEDY TESTING                                        CUSEGXTX                  0                  0           1                1           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCDG0168             GAS EMPLOYEE DEVELOPMENT PROGR                            CUSGOPCO                 19                  -          19               19           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCE13601             GENERAL LITIGATION-ELI                                    DIRCTELI                271                  -         271              271           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCE13751             GENERAL LITIGATION- EGSI-LA                               DIRECTLG                271                  -         271              271           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCEDIVER             DIVERSITY TRAINING                                        DIRCTESI                 90                  -          90               90           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCF96930             BENCHMARKING PHASE II                                     LOADWEOI              4,020                551       4,571            3,817         754            -            16           770
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCLAWELL             LA WELLNESS PROGRAM PILOT                                 CUSTELLA                328                  -         328              328           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCLIHPPC             CONSUMER EDUCATION PROGRAMS                               CUSEOPCO                  3                  -           3                3           1            -             -             1
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCMCMSCL             PASSPORT- SC MATERIALS MANAGEM                            SCMATRAN                257                 31         288              245          43          (43)            -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCSAFTEG             SAFTEY TRAINING LOADER GAS CUS                            CUSGOPCO             82,056              5,482      87,538           87,538           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCSVCAWD             SERVICE AWARDS                                            DIRCTESI              2,504                  -       2,504            2,504           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCTTDS70             TRANS MAINTENANCE: LINES & SUB                            TRSBLNOP            475,946             54,604     530,550          468,094      62,456        4,130         1,099        67,685
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCZCDEPT             SUPERVISION & SUPPORT - CORPOR                            LBRCORPT                813                  -         813              785          28            -           (19)            9
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCZCONOP             CONTRIBUTION OPERATIONS - BELO                            ASSTSALL                  1                  0           1                1           0            -            (0)            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCZECDEV             ECONOMIC DEVELOPMENT - BELOW T                            CUSEOPCO                  2                  0           2                1           0            -            (0)            -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCZFCLSR             VOICE & VIDEO LOCAL SERVICE                               TELXGENS                492                  -         492              463          29            -             -            29
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCZFDSER             DESKTOP SERVICES                                          PCNUMALL                 15                  1          16               16           1            -             0             1
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCZU1425             REGULATORY COORDINAT.-ELI & EG                            CUSELPSC             19,736              2,153      21,889           21,889           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCZU1573             REGULATORY AFFAIRS -- 100% EGS                            DIRECTTX             11,275                  -      11,275                -      11,275            -             -        11,275
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCZU5400             LA GOVERNMENTAL AFFAIRS-100% E                            DIRCTELI                185                  -         185              185           -            -             -             -
3-51




                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCZU5402             LOUISIANA GOVERNMENTAL AFFAIRS                            CUSELGLA             87,279             10,527      97,805           97,805           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCZU5403             LOUISIANA GOVERNMENTAL AFFAIRS                            CUSTELLA            922,728             95,302   1,018,030        1,018,030           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCZUSETR             TRANSITION TO COMPETITION - ET                            DIRCTETR             79,500                  -      79,500           79,500           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCZUSGSL             TRANS TO COMPETITION -EGSI LA-                            DIRECTLG            127,095                  -     127,095          127,095           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCZUSLPL             TRANS TO COMPETITION -ELI- BEL                            DIRCTELI            142,455                  -     142,455          142,455           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCZZ0150             SHAREHOLDER/DIRECTOR EXPENSES                             ASSTSALL                502                  -         502              451          51            -             -            51
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCZZ4070             IMPACT AWARDS                                             DIRCTESI              1,614                  -       1,614            1,614           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PCZZI04R             WORKER'S COMPENSATION- RESERVE                            DIRCTESI            115,736                  -     115,736          115,736           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PP10011U             Show Cause Docket No. 10-011-U                            DIRCTEAI             78,782                  -      78,782           78,782           -            -             -             -
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PPCIPUNC             General Unclassified CIP Costs                            LOADOPCO              7,719                709       8,428            7,170       1,258            -            25         1,283
                     UTILITY & EXECUTIVE MANAGEMENT            ESI          F5PPD10154             MDT Wireless Telecom Serv                                 CUSTEGOP                811                 34         845              729         117            -           (72)           45

                           Amounts may not add or tie to other schedules due to rounding.                                                                                                                                                                                                           EXHIBIT JFD-B
                                                                                                                                                                             Domino, Joe                                                                                                               Page 5 of 6
                                                                                                                                                                      ENTERGY TEXAS, INC.                                                                                                            EXHIBIT JFD-B
2011 ETI Rate Case




                                                                                                                                                       Affiliate Billings - by Witness, Class and Project                                                                                         2011 TX Rate Case
                                                                                                                                                         For the Twelve Months Ended June 30, 2011                                                                                                       Page 6 of 6
                                                                                                                                                                        Amounts in Dollars

                                                                                                                                                                                 (A)              (B)           (C)             (D)          (E)           (F)          (G)           (H)
                                                                                                                                                                                             Total Billings
                                                                   Billing      Activity / Project                                                             ESI Billing                  Service Company                                 ETI Per                   Pro Forma     Total ETI
                                         Class                     Entity             Code                            Activity / Project Description            Method         Support         Recipient        Total      All Other BU's   Books       Exclusions     Amount       Adjusted
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          F5PPD10156             Dist. Work Mgmt - DriveCam Sup                          CUSTELLA                  5                  1           5                5           -             -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          F5PPD10162             Util Ops Cust Data Warehouse S                          CUSTEGOP                 45                  5          50               43           7             -             0              7
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          F5PPERG100             Systemwide Ergonomics Initiati                          EMPLOYAL              4,970                 94       5,064            4,820         244            (5)            1            240
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          F5PPETX009             2009 Texas Rate Case Support                            DIRECTTX                148                  -         148                -         148             -          (148)             -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          F5PPFALCON             Project Falcon                                          DIRECTNI            208,516              4,160     212,676         212,676            -             -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          F5PPGEFBUS             Gas Operations Efficient Busin                          CUSGOPCO             45,084              5,479      50,562           50,562           -             -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          F5PPHREXEC             HR Executive Financial Counsel                          ASSTSALL             46,517                  -      46,517           41,790       4,727             -        (4,727)             -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          F5PPLRSOLT             System Officer Labor Team                               EMPLOYAL              2,871                282       3,153            2,998         155             -             3            158
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          F5PPORGSSP             ESI Direct Enexus Org Costs                             DIRECTNI                  -                  -           -                -           -             -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          F5PPSAFTEL             SAFETY TRAINING LOADER ELEC LA                          CUSTELLA                698                 78         776              776           -             -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          F5PPSPE044             PMO Support Initiative-System-                          LOADOPCO              1,454                167       1,621            1,352         269             -          (269)             -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          F5PPSUPICT             Support of ICT                                          LOADOPCO                  -                  -           -                -           -             -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          F5PPTHMPSN             Norwood Thompson Park Playgrou                          DIRCTETR              3,514                465       3,980            3,980           -             -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          F5PPTRISTE             Project Blue                                            DIRCTETR                  -                  -           -                -           -             -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          F5PPTVPPRO             Voluntary Protection Program                            TRSBLNOP                698                 78         776              685          91             -             2             93
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          F5PPZCONAR             EAI Contributions - BELOW THE                           DIRCTEAI             54,405                  -      54,405           54,405           -             -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          F5PPZCONLA             ELI Contributions - BELOW THE                           DIRCTELI             39,524                  -      39,524           39,524           -             -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          F5PPZCONLS             EGSI-LA Contrib - BELOW THE LI                          DIRECTLG             32,595                  -      32,595           32,595           -             -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          F5PPZCONMS             EMI Contributions - BELOW THE                           DIRCTEMI             39,120                  -      39,120           39,120           -             -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          F5PPZCONNO             ENOI Contributions - BELOW THE                          DIRCTENO             19,456                  -      19,456           19,456           -             -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          F5PPZCONTG             EGSI-TX Contrib - BELOW THE LI                          DIRECTTX             23,251                  -      23,251                -      23,251       (23,251)            -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          F5PPZUWELL             Entergy Wellness Program                                EMPLOYAL              3,503                346       3,849            3,660         189             -           (44)           145
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          SAPCP25910             PC&R OVERHEAD POOL CHARGES                              CEAOUTAL                  0                  -           0                0           0            (0)            -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          SDPCT30070             CAPITAL SUSPENSE, DISTR WIRES,                          DIRCTELI                676                 75         751              751           -             -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          SGPCG59006             GAS DISTRIBUTION ENOI O/H GAS                           DIRCTENO            713,582             85,639     799,221         799,221            -             -             -              -
                     UTILITY & EXECUTIVE MANAGEMENT              ESI          SGPCR79008             GAS DISTRIBUTION EGSI O/H-CHAR                          DIRECTLG            452,571             54,724     507,296         507,296            -             -             -              -

                     UTILITY & EXECUTIVE MANAGEMENT              Total ESI                                                                                                     28,688,315         2,014,250   30,702,565     28,491,933     2,210,631      (39,503)     (231,900)   1,939,228

                     Total UTILITY & EXECUTIVE MANAGEMENT                                                                                                                      28,688,315         2,014,250   30,702,565     28,491,933     2,210,631      (39,503)     (231,900)   1,939,228

                     Total Domino, Joe                                                                                                                                         28,688,315         2,014,250   30,702,565     28,491,933     2,210,631      (39,503)     (231,900)   1,939,228
3-52




                             Amounts may not add or tie to other schedules due to rounding.                                                                                                                                                                                                          EXHIBIT JFD-B
                                                                                                                                                                             Domino, Joe                                                                                                                Page 6 of 6
                                                                                                                                                                             ENTERGY TEXAS, INC.                                                                                                                              EXHIBIT JFD-C
2011 ETI Rate Case




                                                                                                                                                        Affiliate Billings - by Witness, Class, Department and Project                                                                                                     2011 TX Rate Case
                                                                                                                                                                  For the Twelve Months Ended June 30, 2011                                                                                                                      Page 1 of 11
                                                                                                                                                                               Amounts in Dollars
                                                                                                                                                                                            (A)             (B)               (C)              (D)          (E)             (F)              (G)             (H)
                                                                                                                                                                                                        Total Billings
                                                                                             Activity / Project                                                          ESI BIlling                   Service Company                                     ETI Per                        Pro Forma        Total ETI
                                       Class                    Billing Entity      Dept           Code                            Activity / Project Description         Method          Support         Recipient           Total       All Other BU's   Books         Exclusions        Amount          Adjusted
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       C1PPSP0008           SPO ELL&ENOI Purchase Option I                       OWNISES2                   -                 (2)             (2)              (2)           -                  -               -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       C6PCN32144           GRAND GULF EXTENDED POWER UPRA                       DIRCTSER                 796                 96             892              892            -                  -               -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       C6PPSP0012           SPO Project Gator Transact/Tra                       DIRCTELI                 834                 95             928              928            -                  -               -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       C6PPWS0534           System Planning Pet Coke Repow                       DIRCTELI                 274                 31             305              305            -                  -               -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F3PCCSPUTI           SYSTEM PLANNING & STRATEGIC AD                       LOADOPCO              10,566              1,170          11,736            9,984        1,752                  -              37         1,789
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F3PCE99750           PRES- ENT. LA-GEN'L OPS-ELI/EG                       CUSELGLA           1,086,097             67,986       1,154,084        1,154,084            -                  -               -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F3PCE99751           SPECIAL PROJECTS - LA STATE PR                       CUSELGLA                  71                  -              71               71            -                  -               -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F3PCF07300           CORP PLANNING & ANALYSIS- REGU                       CUSTEGOP               3,054                356           3,410            2,940          470                  -              10           480
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F3PCF21600           CORP RPTG ANALYSIS & POLICY AL                       GENLEDAL               4,616                418           5,035            4,717          317                  -               7           324
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F3PCF23033           GENERAL ACCOUNTING - ESI                             LVLSVCAL                 977                135           1,112            1,007          105                  -               2           107
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F3PCF23920           CORP REPORTING ANALYSIS & POLI                       DIRCTELI              32,744              3,899          36,643           36,643            -                  -               -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F3PCF239LA           CORP RPTNG ANALYSIS/POLICY EGS                       DIRECTLG              32,690              3,893          36,583           36,583            -                  -               -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F3PCFACALL           FACILITIES SVCS- ALL COS                             SQFTALLC               1,019                  -           1,019              905          113                  -               -           113
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F3PCSYSAGR           SYSTEM AGREEMENT-2001                                CUSEOPCO                 823                 96             919              783          135                  -               4           140
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F3PCTBLLPL           BELOW THE LINE - LPL                                 DIRCTELI                   -                  -               -                -            -                  -               -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F3PCWE0135           NEL. 6 JOINT OWNERSHIP PART. A                       DIRECTLG                 964                108           1,072            1,072            -                  -               -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F3PCZU1603           LP&L/LPSC EARNINGS REVIEW; DOC                       DIRCTELI               2,335                298           2,633            2,633            -                  -               -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F3PPEGSFRP           EGSI LPSC Formula Rate Plan Fi                       DIRECTLG                 686                 77             763              763            -                  -               -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F3PPSPE003           SPO Summer 2009 RFP Expense                          LOADOPCO               2,871                350           3,221            2,740          481                  -              10           491
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F3PPSPE042           SPO Expense ISES Purchase Opti                       OWNISES2                 543                 70             614              614            -                  -               -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F3PPWE0292           System Planning Asset Manageme                       LOADOPCO                 278                 38             316              263           52                  -               1            53
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F5PCE13601           GENERAL LITIGATION-ELI                               DIRCTELI                 271                  -             271              271            -                  -               -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F5PCE13751           GENERAL LITIGATION- EGSI-LA                          DIRECTLG                 271                  -             271              271            -                  -               -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F5PCLAWELL           LA WELLNESS PROGRAM PILOT                            CUSTELLA                 328                  -             328              328            -                  -               -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F5PCZCDEPT           SUPERVISION & SUPPORT - CORPOR                       LBRCORPT                   2                  -               2                2            0                  -               -             0
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F5PCZFCLSR           VOICE & VIDEO LOCAL SERVICE                          TELXGENS                 492                  -             492              463           29                  -               -            29
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F5PCZU1425           REGULATORY COORDINAT.-ELI & EG                       CUSELPSC              19,736              2,153          21,889           21,889            -                  -               -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F5PCZUSETR           TRANSITION TO COMPETITION - ET                       DIRCTETR              79,500                  -          79,500           79,500            -                  -               -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F5PPHREXEC           HR Executive Financial Counsel                       ASSTSALL               5,979                  -           5,979            5,371          607                  -            (607)            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       F5PPZUWELL           Entergy Wellness Program                             EMPLOYAL                 439                 45             484              460           24                  -               0            24

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE122       Total                                                                                        1,289,256             81,310       1,370,566       1,366,479         4,086                  -            (536)        3,551

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE12F       F3PPELEGAS           ENO Elec & ENO EGS Gas Expense                       CUSENLGG             (19,654)                     -     (19,654)        (19,654)              -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE12F       F3PPENOCEO           ENO CEO Electric and Gas Expen                       DIRCTENO                   -                      -           -               -               -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE12F       F3PPRC2008           ENOI 2008 RATE CASE                                  DIRCTENO                   -                      -           -               -               -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE12F       F5PCSVCAWD           SERVICE AWARDS                                       DIRCTESI                   -                      -           -               -               -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE12F       F5PPERG100           Systemwide Ergonomics Initiati                       EMPLOYAL                   -                      -           -               -               -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE12F       F5PPHREXEC           HR Executive Financial Counsel                       ASSTSALL                   -                      -           -               -               -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE12F       F5PPZUWELL           Entergy Wellness Program                             EMPLOYAL                   -                      -           -               -               -                -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE12F       Total                                                                                          (19,654)                     -     (19,654)        (19,654)              -                -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE179       F3PCE14420           REGULATORY AFFAIRS - EAI                             DIRCTEAI                 26                   -              26              26             -                -                 -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE179       F3PCFACALL           FACILITIES SVCS- ALL COS                             SQFTALLC                686                   -             686             613            73              (73)                -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE179       F3PCTTDS46           DISTRIBUTION O&M EXP - METRO E                       CUSEMETR                159                   -             159             159             -                -                 -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE179       F3PCTTDS47           DISTR O&M EXPENSE - LOUISIANA                        CUSTELLA                943                   -             943             943             -                -                 -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE179       F5PCSVCAWD           SERVICE AWARDS                                       DIRCTESI                 42                   -              42              42             -                -                 -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE179       F5PCZU5400           LA GOVERNMENTAL AFFAIRS-100% E                       DIRCTELI                185                   -             185             185             -                -                 -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE179       F5PCZU5402           LOUISIANA GOVERNMENTAL AFFAIRS                       CUSELGLA             87,279              10,527          97,805          97,805             -                -                 -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE179       F5PCZU5403           LOUISIANA GOVERNMENTAL AFFAIRS                       CUSTELLA            922,728              95,302       1,018,030       1,018,030             -                -                 -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE179       F5PCZUSGSL           TRANS TO COMPETITION -EGSI LA-                       DIRECTLG            127,095                   -         127,095         127,095             -                -                 -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE179       F5PCZUSLPL           TRANS TO COMPETITION -ELI- BEL                       DIRCTELI            142,455                   -         142,455         142,455             -                -                 -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE179       F5PPERG100           Systemwide Ergonomics Initiati                       EMPLOYAL                 93                   8             101              96             5               (5)                -                -
3-53




                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CE179       Total                                                                                        1,281,690            105,837       1,387,527       1,387,448            78              (78)                -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CP015       F5PPZCONAR           EAI Contributions - BELOW THE                        DIRCTEAI              54,405                      -     54,405           54,405            -               -                   -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CP015       F5PPZCONLA           ELI Contributions - BELOW THE                        DIRCTELI              39,524                      -     39,524           39,524            -               -                   -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CP015       F5PPZCONLS           EGSI-LA Contrib - BELOW THE LI                       DIRECTLG              32,595                      -     32,595           32,595            -               -                   -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CP015       F5PPZCONMS           EMI Contributions - BELOW THE                        DIRCTEMI              39,120                      -     39,120           39,120            -               -                   -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CP015       F5PPZCONNO           ENOI Contributions - BELOW THE                       DIRCTENO              19,456                      -     19,456           19,456            -               -                   -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CP015       F5PPZCONTG           EGSI-TX Contrib - BELOW THE LI                       DIRECTTX              23,251                      -     23,251                -       23,251         (23,251)                  -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CP015       Total                                                                                         208,351                       -    208,351          185,100       23,251         (23,251)                  -                -


                            Amounts may not add or tie to other schedules due to rounding.
                                                                                                                                                                                                                                                                                                                              EXHIBIT JFD-C
                                                                                                                                                                                       Domino, Joe                                                                                                                              Page 1 of 11
                                                                                                                                                                               ENTERGY TEXAS, INC.                                                                                                                               EXHIBIT JFD-C
2011 ETI Rate Case




                                                                                                                                                          Affiliate Billings - by Witness, Class, Department and Project                                                                                                      2011 TX Rate Case
                                                                                                                                                                    For the Twelve Months Ended June 30, 2011                                                                                                                       Page 2 of 11
                                                                                                                                                                                 Amounts in Dollars
                                                                                                                                                                                              (A)              (B)               (C)              (D)          (E)             (F)              (G)             (H)
                                                                                                                                                                                                           Total Billings
                                                                                             Activity / Project                                                            ESI BIlling                    Service Company                                     ETI Per                        Pro Forma        Total ETI
                                       Class                    Billing Entity    Dept             Code                              Activity / Project Description         Method          Support          Recipient           Total       All Other BU's   Books         Exclusions        Amount          Adjusted
                     UTILITY & EXECUTIVE MANAGEMENT             ESI            CP027         F5PCZCDEPT           SUPERVISION & SUPPORT - CORPOR                         LBRCORPT                     -                     -            -               -              -                -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP027          Total                                                                                                    -                     -            -               -              -                -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PCC14900           EXPENSES-CHAIRMAN ENTERGY                              DIRCTETR             448,364              56,234         504,599         504,599            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PCC31255           OPERATIONS-OFFICE OF THE CEO                           ASSTSALL           3,036,304             193,032       3,229,335       2,909,321      320,015            (645)          (4,828)        314,542
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PCC31256           LEADERSHIP CONFERENCE                                  EMPLOYAL             186,861                   -         186,861         178,151        8,711               -                -           8,711
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PCC31257           EVENTS ADMINISTRATION                                  DIRCTETR             814,340                   -         814,340         814,340            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PCCE0155           BELOW THE LINE-C ENVIRONMENTAL                         CAPAOPCO                   -                   -               -               -            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PCCEP001           CORPORATE ENVIRONMENTAL POLICY                         CAPAOPCO                   -                   -               -               -            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PCE14987           FGA-Climate/Environmental                              ASSTSALL              47,580                   -          47,580          42,787        4,793          (4,793)               -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PCE99750           PRES- ENT. LA-GEN'L OPS-ELI/EG                         CUSELGLA              28,711               2,769          31,480          31,480            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PCF22511           IR - GENERAL, INQUIRIES & MAIL                         DIRCTETR                 404                   -             404             404            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PCF22514           MEETINGS ANALYSTS/INVESTORS/SH                         DIRCTETR               5,306                   -           5,306           5,306            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PCFACALL           FACILITIES SVCS- ALL COS                               SQFTALLC                 359                  29             388             343           45               -                1              46
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PCFEXETR           EXECUTIVE ADVISORY SERVICES -                          DIRCTETR              22,703               2,858          25,562          25,562            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PCH60959           EXECUTIVE FACILITIES SERVICES                          DIRCTETR                 348                   -             348             348            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PCHRSALL           HR SERVICES- ALL COMPANIES                             EMPLOYAL              85,865               8,419          94,283          89,655        4,628               -               96           4,724
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PCR40085           ENTERGY CORPORATION COMMUNICAT                         DIRCTETR              10,500                   -          10,500          10,500            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PP1E2EPM           End-to-End Process Mgmnt                               LVLSVCAL               3,230                 407           3,637           3,291          347               -                7             354
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PPBLANCO           Project White                                          DIRCTETR              38,891               5,003          43,894          43,894            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PPC31258           CEO MEETINGS WITH EMPLOYEES                            EMPLOYAL                 350                   -             350             334           16               -                -              16
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PPCAO001           Chief Administrative Officer                           ASSTSALL              11,990                   -          11,990          10,770        1,220               -           (1,048)            172
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PPETENOI           Executive Timesheet- ENOI                              DIRCTENO               5,995                   -           5,995           5,995            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PPETSELI           Executive Timesheets- ELI                              DIRCTELI               5,995                   -           5,995           5,995            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PPETSETI           Executive Time and Expenses-ET                         DIRECTTX               6,980                 641           7,621               -        7,621               -              164           7,785
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PPETSETR           Executive Timesheets-ETR                               DIRCTETR             408,416              55,057         463,472         463,472            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PPHIPPO1           Project X                                              DIRCTETR              34,735               5,181          39,916          39,916            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F3PPHRTFMN           HR Transformation - O&M Costs                          EMPLOYAL              32,084               3,203          35,288          33,559        1,728               -               36           1,764
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F5PCZCDEPT           SUPERVISION & SUPPORT - CORPOR                         LBRCORPT                 190                   -             190             184            6               -                -               6
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F5PCZCONOP           CONTRIBUTION OPERATIONS - BELO                         ASSTSALL                   -                   -               -               -            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F5PCZZ0150           SHAREHOLDER/DIRECTOR EXPENSES                          ASSTSALL                 502                   -             502             451           51               -                -              51
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F5PCZZI04R           WORKER'S COMPENSATION- RESERVE                         DIRCTESI             115,736                   -         115,736         115,736            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F5PPFALCON           Project Falcon                                         DIRECTNI              30,097               4,160          34,257          34,257            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F5PPHREXEC           HR Executive Financial Counsel                         ASSTSALL              15,000                   -          15,000          13,474        1,526               -           (1,526)              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F5PPLRSOLT           System Officer Labor Team                              EMPLOYAL               2,871                 282           3,153           2,998          155               -                3             158
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          F5PPZUWELL           Entergy Wellness Program                               EMPLOYAL                 (61)                  -             (61)            (58)          (3)              -               (0)             (3)

                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP040          Total                                                                                          5,400,646             337,276       5,737,922       5,387,064      350,858          (5,438)          (7,095)        338,326

                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP050          E1PPNXCRP1           Unwind - Employee                                      DIRECTNI             21,844                3,253          25,096          25,096             -                -                 -              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP050          F3PC6H0026           NORTHEAST MGMT OVERSITE IP2/IP                         SPL77N7A             24,988                    -          24,988          24,988             -                -                 -              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP050          F3PC6HENNE           ENN EQUAL SPLIT                                        DIRCTENU                588                    -             588             588             -                -                 -              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP050          F3PCR93300           NORTHEAST NONREG NUCLEAR EXTRN                         DIRCTENU                  -                    -               -               -             -                -                 -              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP050          F3PP4R9886           TRITIUM DETECTION INVESTIGATIO                         DIRECT72                  -                    -               -               -             -                -                 -              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP050          F3PPCOO001           CHIEF OPERATING OFFICER                                ASSTSALL             11,998                    -          11,998          10,777         1,221                -              (712)           509
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP050          F3PPF15115           FGA-VP/General Office                                  CUSTEGOP                199                    -             199             171            28              (28)                -              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP050          F3PPN20713           ESI Nuclear - Site Split                               SNUCSITE                981                    -             981             981             -                -                 -              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP050          F3PPNPM008           Wholesale C B 50/50 Split - Pi                         DIRNG000                  -                    -               -               -             -                -                 -              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP050          F3PPNXRECR           Enexus Recurring                                       DIRECTNI             (2,989)                   -          (2,989)         (2,989)            -                -                 -              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP050          F3PPSCOUT1           Project Scout (VY Litigation A                         DIRECT72                 15                    -              15              15             -                -                 -              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP050          F3PPWCBEAM           Wholesale Commodity Business -                         DIRECTXU             56,322                6,557          62,878          62,878             -                -                 -              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP050          F3PPWCBEPM           Wholesale Commodity Business -                         DIRNG000                350                    -             350             350             -                -                 -              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP050          F3PPWCBETC           Wholesale Commodity Business -                         DIRECT66             56,322                6,557          62,879          62,879             -                -                 -              -
3-54




                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP050          F3PPWCBNNE           Wholesale Commodity Business -                         SENUCALL            994,973               80,212       1,075,184       1,075,184             -                -                 -              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP050          F5PCZCDEPT           SUPERVISION & SUPPORT - CORPOR                         LBRCORPT                  -                    -               -               -             -                -                 -              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP050          F5PPFALCON           Project Falcon                                         DIRECTNI            178,778                    -         178,778         178,778             -                -                 -              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP050          F5PPHREXEC           HR Executive Financial Counsel                         ASSTSALL              3,400                    -           3,400           3,054           346                -              (346)             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP050          F5PPORGSSP           ESI Direct Enexus Org Costs                            DIRECTNI                  -                    -               -               -             -                -                 -              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP050          F5PPTRISTE           Project Blue                                           DIRCTETR                  -                    -               -               -             -                -                 -              -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP050          Total                                                                                          1,347,769              96,578       1,444,347       1,442,753         1,594              (28)        (1,058)              509

                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP083          C7PPSJ1244           STORM DL ARK DIST EAI 1/7/11 I                         DIRCTEAI                  98                   13            111             111               -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP083          C7PPSJ2462           STORM DMG LA DIST ELL 1/8/11 I                         DIRCTELI               1,422                  231          1,654           1,654               -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CP083          C7PPSJ3198           EMI Storm Distr Ops 1/7/11Wint                         DIRCTEMI               1,062                  144          1,206           1,206               -                -               -                -

                            Amounts may not add or tie to other schedules due to rounding.
                                                                                                                                                                                                                                                                                                                                 EXHIBIT JFD-C
                                                                                                                                                                                         Domino, Joe                                                                                                                               Page 2 of 11
                                                                                                                                                                               ENTERGY TEXAS, INC.                                                                                                                       EXHIBIT JFD-C
2011 ETI Rate Case




                                                                                                                                                          Affiliate Billings - by Witness, Class, Department and Project                                                                                              2011 TX Rate Case
                                                                                                                                                                    For the Twelve Months Ended June 30, 2011                                                                                                               Page 3 of 11
                                                                                                                                                                                 Amounts in Dollars
                                                                                                                                                                                              (A)             (B)            (C)              (D)           (E)           (F)              (G)             (H)
                                                                                                                                                                                                          Total Billings
                                                                                             Activity / Project                                                            ESI BIlling                   Service Company                                   ETI Per                      Pro Forma        Total ETI
                                       Class                    Billing Entity      Dept           Code                              Activity / Project Description         Method          Support         Recipient        Total       All Other BU's    Books       Exclusions        Amount          Adjusted
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CP083       E2PPLG11DA           Logistics Jan 2011 DIST Ark                            DIRCTEAI                  0                  (2)         (2)                (2)          -                 -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CP083       E2PPLG11DL           Logistics Jan 2011 DIST ELL                            DIRCTELI                  0                 (15)        (15)               (15)          -                 -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CP083       E2PPLG11DM           Logistics Jan 2011 DIST Miss                           DIRCTEMI                  0                 (25)        (25)               (25)          -                 -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CP083       E2PPLG11TL           Logistics Jan 2011 TRN ELL                             DIRCTELI                  -                  (0)         (0)                (0)          -                 -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CP083       E2PPLG11TM           Logistics Jan 2011 TRN Miss                            DIRCTEMI                  -                  (1)         (1)                (1)          -                 -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CP083       E2PPSJ2447           T-Grid Storm O&M ELL 1/7/201 I                         DIRCTELI                 11                   2          13                 13           -                 -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CP083       E2PPSJ3188           T-Grid Storm Damage EMI 1/7/11                         DIRCTEMI                 28                   4          31                 31           -                 -              -              -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CP083       F3PCE99741           Utl Ops ECI & 6-Sigma Improve                          CUSEOPCO                249                   -         249               212           37                 -              -             37
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CP083       F3PPE9974S           Utl ECI Continuing Improve ESI                         CUSEOPCO            221,118              23,536     244,654           208,517       36,137                 -            479         36,615

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CP083       Total                                                                                           223,988              23,886     247,874          211,700        36,173                 -            479         36,652

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPCA5       F3PCFACALL           FACILITIES SVCS- ALL COS                               SQFTALLC              2,881                 254       3,135            2,784           350                 -               7           357
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPCA5       F3PCFEXETR           EXECUTIVE ADVISORY SERVICES -                          DIRCTETR             21,917               2,963      24,880           24,880             -                 -               -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPCA5       F3PCHRSALL           HR SERVICES- ALL COMPANIES                             EMPLOYAL            230,926              25,032     255,958          243,721        12,238                 -            (168)       12,069
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPCA5       F3PPETSETR           Executive Timesheets-ETR                               DIRCTETR              8,835               1,266      10,101           10,101             -                 -               -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPCA5       F3PPHRTFMN           HR Transformation - O&M Costs                          EMPLOYAL             58,251               6,624      64,875           61,770         3,105                 -              63         3,168

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPCA5       Total                                                                                           322,809              36,140     358,949          343,256        15,693                 -             (98)       15,595

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPCAO       F3PPCAO001           Chief Administrative Officer                           ASSTSALL           1,419,507            145,499    1,565,006       1,410,828       154,178             (769)       (5,851)        147,559
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPCAO       F3PPELEGAS           ENO Elec & ENO EGS Gas Expense                         CUSENLGG              10,027             (2,615)       7,412           7,412             -                -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPCAO       F5PCSVCAWD           SERVICE AWARDS                                         DIRCTESI                 171                  -          171             171             -                -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPCAO       F5PPERG100           Systemwide Ergonomics Initiati                         EMPLOYAL                 325                  -          325             309            16                -             -              16
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPCAO       F5PPHREXEC           HR Executive Financial Counsel                         ASSTSALL               4,308                  -        4,308           3,871           437                -          (437)              -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPCAO       Total                                                                                          1,434,339            142,884    1,577,223       1,422,591       154,631             (769)       (6,288)        147,574

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP7       C6PPWGP516           SBC CIP Compliance                                     DIRECTTX              12,289              1,679       13,968               -        13,968       (13,968)               -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP7       F3PCT54052           Trans Regulatory Support/Polic                         TRSBLNOP               9,442                868       10,310           9,099         1,211             -               24           1,235
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP7       F3PCW29608           TRANSMISSION POWER SYSTEM OPER                         LOADOPCO               6,950                639        7,589           6,456         1,133             -               22           1,155
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP7       F3PPPCS001           Critical Infrastructure Protec                         CAPAOPCO           1,639,281            151,034    1,790,314       1,596,762       193,553             -            2,377         195,930
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP7       F3PPWE0504           M0000 - CIP Walkdown                                   DIRCTEMI               2,970                209        3,179           3,179             -             -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP7       F3PPWE0505           N0000 - CIP Walkdown                                   DIRCTENO               2,404                213        2,617           2,617             -             -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP7       F3PPWE0506           A0000 - CIP Walkdown                                   DIRCTEAI                 825                  -          825             825             -             -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP7       F3PPWE0507           L0000 - CIP Walkdown                                   DIRCTELI               5,220                481        5,701           5,701             -             -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP7       F3PPWEOSGN           General System-ENG-Tech Suppor                         CAPAOPCO                 598                  -          598             533            65             -                -              65
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP7       F5PCEDIVER           DIVERSITY TRAINING                                     DIRCTESI                  90                  -           90              90             -             -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP7       F5PCSVCAWD           SERVICE AWARDS                                         DIRCTESI                  78                  -           78              78             -             -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP7       F5PCZZ4070           IMPACT AWARDS                                          DIRCTESI               1,399                  -        1,399           1,399             -             -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP7       F5PPCIPUNC           General Unclassified CIP Costs                         LOADOPCO               7,719                709        8,428           7,170         1,258             -               25           1,283
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP7       F5PPZUWELL           Entergy Wellness Program                               EMPLOYAL                 177                 18          194             185            10             -                0              10

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP7       Total                                                                                          1,689,442            155,849    1,845,292       1,634,094       211,197       (13,968)           2,448         199,678

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       C1PPFI5207           Payroll Time & Labor - Phase I                         EMPLOYAL                 (24)                (2)         (27)            (26)           (1)               0                1            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       C1PPHR8800           PS HCM (Human Cap Mgmt) Upgrd                          EMPLOYAL                  (9)                (1)         (10)            (10)           (0)               0                0            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       C6PPAMBSGN           AMI:BASE Non-Incremental, EGSL                         DIRECTLG                 (53)                (7)         (60)            (60)            -                -                -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       C6PPWS0783           Ninemile 6 Development                                 DIRCTELI               8,423              1,072        9,495           9,495             -                -                -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       E1PCD10064           DISTR WK MGMT-SUBST AOR/COS/SF                         CUSEOPCO                   1                  0            1               1             0                -                0            0
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCC08500           Executive VP, Operations                               ASSTSALL              17,701                951       18,652          16,787         1,864                -              (96)       1,768
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCC31257           EVENTS ADMINISTRATION                                  DIRCTETR              11,990                  -       11,990          11,990             -                -                -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCCEP001           CORPORATE ENVIRONMENTAL POLICY                         CAPAOPCO           2,196,785                  -    2,196,785       1,959,288       237,496                -                -      237,496
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCCPM001           CORPORATE PERFORMANCE MANAGEME                         ASSTSALL               2,768                372        3,140           2,824           316                -                7          323
3-55




                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCCSE060           SAFETY & ENVIRONMENTAL SUPPORT                         EMPLOYAL                 747                 62          810             770            40                -                1           41
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCCSPUTI           SYSTEM PLANNING & STRATEGIC AD                         LOADOPCO              17,102              2,200       19,302          16,340         2,962                -               61        3,022
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCD10006           FIELD DEVELOPMENT                                      CUSTEGOP                   6                  1            7               6             1                -                0            1
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCD10010           PROGRAM MANAGEMENT - O&M                               CUSTEGOP                   9                  1           10               8             1                -                0            1
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCD10033           SSS PRELIMINARY PLANNING, SCOP                         CUSTEGOP                   0                  0            0               0             0                -                0            0
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCD10049           REGULATED RETAIL SYSTEMS - O&M                         CUSTEGOP                  25                  3           28              24             4                -                0            4
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCD10077           REGULATORY AFFAIRS WORLDOX IMP                         DIRCTENO                   4                  1            5               5             -                -                -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCD10105           CUSTOMER CARE SYSTEM SUPPORT                           CUSEGXTX                  83                 10           93              93             -                -                -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCE13100           GEN CORP. LEGAL ENTERGY CORP.                          DIRCTETR               3,792                552        4,344           4,344             -                -                -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCE13321           ESI GENERAL LEGAL ADVICE                               LVLSVCAL               3,792                552        4,344           3,931           413                -                8          421
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCF07300           CORP PLANNING & ANALYSIS- REGU                         CUSTEGOP               6,572                804        7,376           6,359         1,017                -               21        1,038
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCF10414           ESI TAX SERVICES                                       LVLSVCAL                  24                  3           27              24             3                -                0            3

                            Amounts may not add or tie to other schedules due to rounding.
                                                                                                                                                                                                                                                                                                                         EXHIBIT JFD-C
                                                                                                                                                                                         Domino, Joe                                                                                                                       Page 3 of 11
                                                                                                                                                                             ENTERGY TEXAS, INC.                                                                                                              EXHIBIT JFD-C
2011 ETI Rate Case




                                                                                                                                                        Affiliate Billings - by Witness, Class, Department and Project                                                                                     2011 TX Rate Case
                                                                                                                                                                  For the Twelve Months Ended June 30, 2011                                                                                                      Page 4 of 11
                                                                                                                                                                               Amounts in Dollars
                                                                                                                                                                                            (A)            (B)           (C)             (D)          (E)          (F)              (G)          (H)
                                                                                                                                                                                                       Total Billings
                                                                                             Activity / Project                                                          ESI BIlling                  Service Company                                ETI Per                     Pro Forma     Total ETI
                                       Class                    Billing Entity     Dept            Code                            Activity / Project Description         Method          Support        Recipient       Total      All Other BU's   Books      Exclusions        Amount       Adjusted
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCF10445           ENTERGY CONSOLIDATED TAX SERVI                       ASSTSALL                   2                 0           2               2           0                -            0            0
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCF15260           IT - BUSINESS & PROJECT SUPPOR                       CAPAOPCO                   5                 1           5               5           1                -            0            1
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCF23425           ACCOUNTS PAYABLE PROCESSING                          APTRNALL                 190                17         207             188          19                -            0           19
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCF23428           TREASURY SYSTEMS                                     BNKACCTA                  69                 8          77              75           2                -            0            2
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCF23442           PAYROLL PROCESSING                                   PRCHKALL                  89                 8          98              93           5                -            0            5
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCF24910           PROPERTY ACCOUNTING- FIXED ASS                       ASSTLOCA                  59                 7          67              60           7                -            0            7
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCF26910           REVENUE ACCOUNTING ANALYSIS                          CUSEGALL                  40                 5          45              38           6                -            0            6
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCF72271           DATA WAREHOUSE                                       GENLEDAL                  67                 6          74              69           4                -            0            4
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCF72670           GENERAL ACCOUNTING SYSTEM MAIN                       GENLEDAL                 823                76         899             847          52                -            1           53
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCF72901           MOBILE DATA TERMINAL BASELOAD                        CUSTEGOP                   5                 1           6               5           1                -            0            1
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCF73027           BUDGET SYSTEM MAINTENANCE                            GENLEDAL                 153                14         168             158          10                -            0           10
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCF73901           AM/FM BASELOAD (SUPPORT)                             DIRECTTX                   3                 0           3               -           3                -            0            3
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCF74195           TRANSMISSION APPLICATION SUPPO                       TRSBLNOP                 161                19         180             159          21                -            0           22
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCF74341           ISB MAINT                                            LOADWEPI                   5                 1           5               5           1                -            0            1
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCF74344           GENERATION PLANNING & DISPATCH                       LOADOPCO                  20                 2          22              19           3                -            0            3
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCF74515           FOSSIL MAINTENANCE MANAGEMENT                        CAPAOPCO                  40                 5          45              40           5                -            0            5
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCF74585           FOSSIL APPLICATION SUPPORT                           CAPAOPCO                  43                 5          48              42           5                -            0            5
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCF99182           RECORDS MANAGEMENT                                   RECDMGNT                  11                 1          12              10           1                -            0            1
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFCPO01           CHIEF PROCUREMENT OFFICER                            SCPSPALL               8,175               980       9,155           8,049       1,106                -           23        1,128
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFCQEAI           ENTERPRISE APPLICATION INTEGRA                       APPSUPAL                 292                32         323             274          49                -            1           50
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFCQEXC           EXCHANGE                                             PCNUMALL                 312                26         338             325          13                -            0           14
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFCQMVS           MAINFRAME                                            APPSMVSX                   -                 -           -               -           -                -             -           -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFCQNTS           NT SERVERS                                           APPSWINT                   -                 -           -               -           -                -             -           -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFCQUNX           UNIX SERVERS                                         APPSUNIX                   -                 -           -               -           -                -             -           -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFX2770           HR SERVICE CENTER SUPPORT                            EMPLOYAL                   -                 -           -               -           -                -             -           -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFX2815           EDMS PRODUCT LINE SUPPORT                            EMPLOYAL                  60                 6          66              63           3                -            0            3
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFX2850           SECRETARIAT LEGAL SUPPORT                            ASSTSALL                   4                 0           5               4           1                -            0            1
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFX3265           POWERBUILDER FRAMEWORK BASELOA                       APPSUPAL                   5                 0           5               4           1                -            0            1
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFX3275           WEB INFRASTRUCTURE MAINTENANCE                       PCNUMALL                   9                 1          10               9           0                -            0            0
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFX3290           IT BUSINESS PLANNING AND GOVER                       ITSPENDA               3,818               470       4,288           4,002         285                -            6          291
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFX3350           A/R & BILLING SUPPORT                                ARTRNALL                  72                 8          80              71           9                -            0            9
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFX3355           Property Software Support                            GENLEDAL                   3                 0           3               3           0                -            0            0
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFX3450           CORPORATE REPORTING SYSTEM SUP                       GENLEDAL                   0                 -           0               0           -                -             -           -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFX3620           MMIS MATERIALS MAINT MGMNT INF                       DIRCTESI                   0                 -           0               0           -                -             -           -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFX3625           SUPPLY CHAIN - CDW SYSTEMS SUP                       SCDSPALL                   4                 0           4               3           2                -            0            2
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFX3640           WHITE AMBER & ITILITI SUPPORT                        SCMATRAN                   -                 -           -               -           -                -             -           -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFX3650           WEB PAGE SUPPORT - CORPORATE                         EMPLOYAL                   1                 0           1               1           0                -            0            0
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFX3670           CORPORATE COMMUNICATIONS WEB S                       DIRCTETR                   4                 0           4               4           -                -             -           -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFX3675           BARCODING SYSTEMS SUPPORT                            SCDSPALL                   2                 0           2               1           1                -            0            1
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFX3690           PEARL SUPPORT                                        APTRNALL                   1                 0           1               1           0                -            0            0
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFX3695           ATPR SUPPORT                                         APTRNALL                  61                 6          67              61           6                -            0            6
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFX3785           ORG, JES, BATS, ACBM SUPPORT                         GENLEDAL                   0                 -           0               0           -                -             -           -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFX3790           ESTER SUPPORT                                        PRCHKALL                  95                 9         104              99           5                -            0            5
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCFX5555           DATA WAREHOUSE TOOLS SUPPORT                         APPSUPAL                  25                 3          28              24           4                -            0            4
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCHRFOSS           HR FOSSIL SUPPORT- ALL COS                           EMPLOFOS                 537                 -         537             488          48                -             -          48
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCHRSALL           HR SERVICES- ALL COMPANIES                           EMPLOYAL                 326                31         357             339          17                -            0           18
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCHRTRAN           HUMAN RESOURCE SVCS - TRANSMIS                       EMPLTRAN                 115                 -         115             106           9                -             -           9
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCMCMSOM           MATERIALS & CONTRACTS MGTMT SY                       SCMATXNU                   -                 -           -               -           -                -             -           -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCN20520           WORK MANAGEMENT SYSTEM (WMS) M                       DIRCTEOI                  25                 3          28              28           -                -             -           -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCN20521           IDEAS MAINTENANCE                                    DIRCTEOI                  76                 9          86              86           -                -             -           -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCN20522           PCRS MAINTENANCE                                     DIRCTEOI                 133                16         149             149           -                -             -           -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCN20527           NUCLEAR IT QUICK RESPONSE TEAM                       DIRCTEOI                  44                 5          49              49           -                -             -           -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCN20528           ERD SUPPORT (MAINTENANCE)                            DIRCTEOI                 617                74         691             691           -                -             -           -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCN20858           NUCLEAR IT QUICK RESPONSE TEAM                       DIRCTEOI                   2                 0           3               3           -                -             -           -
3-56




                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCR40500           EMPLOYEE COMM (REG + UNREG COM                       EMPLOYAL                   4                 0           5               5           0                -            0            0
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCR53095           HEADQUARTER'S CREDIT & COLLECT                       CUSTEGOP                   0                 -           0               0           -                -             -           -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCR53291           ESI REMITTANCE PROCESSING                            CUSEOPCO                 151                18         170             145          25                -            1           26
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCR73326           CUSTOMER SERVICE CENTER SUPPOR                       CUSTCALL                 130                16         146             130          16                -            0           16
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCR73380           CREDIT SYSTEMS                                       CUSTEGOP                  40                 5          44              38           6                -            0            6
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCRM1021           AUDIT: ESI INFORMATION TECHNO                        DIRCTESI                   3                 -           3               3           -                -             -           -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCSYSRAS           SYSTEM REGULATORY AFFAIRS-STAT                       CUSTEGOP                   -                 -           -               -           -                -             -           -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCT54065           OPNS OF PURCHASING & CONT-DCS                        SCMATRAN                   0                 0           0               0           0                -            0            0
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCTDPQ01           DISTR POWER QUALITY ESI                              CUSEOPCO                   3                 0           3               2           0                -            0            0
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCTTDS38           TRANSMISSION O&M MGMT/SUPPORT                        TRSBLNOP           1,871,437             4,636   1,876,073       1,655,627     220,446                -           90      220,536
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCW29607           POWER SYSTEM ACCOUNTING                              LOADWEPI                   3                 0           4               3           1                -            0            1
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCW55555           VP FOSSIL GENERATION                                 CAPAOPCO              14,414             1,850      16,265          14,506       1,758                -           32        1,791

                            Amounts may not add or tie to other schedules due to rounding.
                                                                                                                                                                                                                                                                                                              EXHIBIT JFD-C
                                                                                                                                                                                       Domino, Joe                                                                                                              Page 4 of 11
                                                                                                                                                                               ENTERGY TEXAS, INC.                                                                                                                 EXHIBIT JFD-C
2011 ETI Rate Case




                                                                                                                                                          Affiliate Billings - by Witness, Class, Department and Project                                                                                        2011 TX Rate Case
                                                                                                                                                                    For the Twelve Months Ended June 30, 2011                                                                                                         Page 5 of 11
                                                                                                                                                                                 Amounts in Dollars
                                                                                                                                                                                              (A)             (B)          (C)             (D)          (E)           (F)             (G)           (H)
                                                                                                                                                                                                          Total Billings
                                                                                             Activity / Project                                                            ESI BIlling                   Service Company                               ETI Per                     Pro Forma      Total ETI
                                       Class                    Billing Entity     Dept            Code                              Activity / Project Description         Method          Support         Recipient      Total      All Other BU's   Books       Exclusions       Amount        Adjusted
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCWE0063           EMO APPLICATION SUPPORT                                LOADOPCO                  17                  2        19               16           3               -              0             3
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCWE0073           FOSSIL INFORMATION TECHNOLOGY                          CAPAOPCO                   3                  0         3                3           0               -              0             0
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCWE0187           FOSSIL IT SUPPORT FOR 2003-200                         CAPAOPCO                   -                  -         -                -           -               -              -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCWS0327           SAIC LABOR CHARGES TO PMDC                             CAPAOPCO                  53                  6        60               53           7               -              0             7
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PP4R9886           TRITIUM DETECTION INVESTIGATIO                         DIRECT72              23,182              2,309    25,491           25,491           -               -              -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PP6HHOST           ENNE Hosting/server support/SO                         DIRCTENU                 135                 16       151              151           -               -              -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PP6HINDS           Indus Passport                                         DIRCTENU                 339                 41       379              379           -               -              -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPAMISTG           AMI Strategy Expense                                   CUSEOPCO                 222                 27       249              212          37               -              1            37
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPCCS010           Climate Consulting Services                            ASSTSALL            289,337              31,693   321,030          289,415      31,615               -            547        32,162
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPCOO001           CHIEF OPERATING OFFICER                                ASSTSALL            570,386              63,085   633,471          571,034      62,437              (3)        (1,403)       61,032
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPD10115           Dist Work Mgmt O&M-DIS/DSS/ADS                         CUSTEGOP                 176                 21       197              170          27               -              1            28
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPD10116           Dist Work Mgmt O&M-LAMP Street                         CUSEOPCO                   1                  0         1                1           0               -              0             0
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPD10119           Dist Work Mgmt O&M-CTS Contrac                         CUSTEGOP                  23                  3        26               22           4               -              0             4
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPD10120           Dist Oper Appl O&M-AM/FM Suppo                         CUSTEGOP                 269                 32       302              260          42               -              1            42
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPD10121           Dist Oper Appl O&M-AutoCAD                             CUSEOPCO                  12                  1        14               12           2               -              0             2
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPD10123           Dist Oper Appl O&M-EPO&SAISO S                         CUSEOPCO                  21                  3        24               20           4               -              0             4
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPD10124           Dist Oper Appl O&M-PDD/ECOS Sp                         CUSTEGOP                   8                  1         9                8           1               -              0             1
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPD10128           ARCS/Itron/MV90 Support                                CUSTEGOP                  73                  9        82               71          11               -              0            12
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPD10129           Billing Determinate Proc/Major                         CUSTEGOP                  56                  7        62               54           9               -              0             9
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPD10130           Customer Care System Interface                         CUSEGXTX                  98                 12       109              109           -               -              -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPD10131           CIS/AIS & Core Support                                 DIRECTTX                 805                 97       902                -         902               -             19           921
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPD10132           Electronic Data Interchange Su                         CUSEOPCO                  20                  2        23               19           3               -              0             3
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPD10133           Internet Bill Presentment & Pm                         CUSEGXTX                  15                  2        17               17           -               -              -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPD10134           MAB Load Research Support                              CUSTEGOP                  19                  2        22               19           3               -              0             3
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPD10137           Bill Delivery Support                                  CUSEGXTX                 482                 58       539              539           -               -              -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPD10139           Mobius Support                                         CUSTEGOP                   0                  0         0                0           0               -              0             0
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPD10140           Large Power Billing System for                         CUSEOPCO                  23                  3        25               22           4               -              0             4
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPD10141           CIMS Support                                           CUSEGXTX                   2                  0         2                2           -               -              -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPD10142           Customer Service Field Applica                         CUSTEGOP                  11                  1        12               10           2               -              0             2
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPD10146           Dist Work Mgmt-Cyndrus Support                         VEHCLALL                   8                  1         9                8           1               -              0             1
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPD10150           TaxWare Support                                        CUSTEGOP                  50                  6        56               48           8               -              0             8
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPD10158           CCS Agent Care System                                  CUSEGXTX                  46                  6        52               52           -               -              -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPD10161           ePlus (Web Self Service) Suppo                         CUSTEGOP                 146                 17       163              141          22               -              0            23
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPEPI001           Environmental Programs & Infra                         CAPAOPCO                (179)                 -      (179)            (160)        (19)              -             (1)          (20)
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPETRNUC           Executive Timesheets- Reg Nuc                          DIRCTEOI              17,530              1,880    19,410           19,410           -               -              -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPETSETR           Executive Timesheets-ETR                               DIRCTETR            320,645              40,720   361,365          361,365           -               -              -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPETSNRG           Executive Timesheets- Non Reg                          DIRCTENU              10,307                595    10,902           10,902           -               -              -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPETSREG           Executive Timesheets- Reg Co's                         CUSTEGOP              12,783                865    13,648           11,767       1,882               -             29         1,911
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPF72700           Cognos Reporting Support                               GENLEDAL                  22                  2        24               23           1               -              0             1
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPFRM127           OCRO - Bus Cont Plan Managemen                         LBRBILAL                   -                  -         -                -           -               -              -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPFX3259           Inventory Planning System Supp                         SCTDSPAL                  34                  4        38               25          12               -              0            13
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPFX3685           Supply Chain Applications Supp                         SCMATRAN                  61                  7        68               58          10               -              0            10
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPFX5307           Compliance Software System Sup                         ASSTSALL                  38                  5        42               38           4               -              0             4
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPFXOPMO           IT Enterprise Program Manageme                         ITSPENDA                  22                  2        25               23           2               -              0             2
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPHRSSPC           HR SVS - ESI SUPPLY CHAIN                              DIRCTESI                  18                  -        18               18           -               -              -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPN20535           P3E Scheduling Software Mainte                         DIRCTEOI                 162                 19       182              182           -               -              -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPN20536           INDUS Software Maintenance                             DIRCTEOI                 288                 34       322              322           -               -              -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPN20713           ESI Nuclear - Site Split                               SNUCSITE              80,170             10,163    90,333           90,333           -               -              -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPPCS001           Critical Infrastructure Protec                         CAPAOPCO               5,554                762     6,316            5,633         683               -             14           697
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPPMUPGR           Performance Management Sys Upg                         CUSEOPCO                   3                  0         4                3           1               -              0             1
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPRES001           Regulated Utility Electric Rel                         CUSEOPCO               1,993                223     2,216            1,889         327               -              7           333
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PCTTDS38           TRANSMISSION O&M MGMT/SUPPORT                          TRSBLNOP                   -                  -         -                -           -               -      (215,886)      (215,886)
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPWE0375           SAIC Designated Srv for Fossil                         CAPAOPCO                  10                  1        11               10           1               -              0             1
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F3PPWEOSGN           General System-ENG-Tech Suppor                         CAPAOPCO                 504                 80       584              521          63               -              1            64
3-57




                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F5PCD10093           WEB DEVELOPMENT SUPPORT                                CUSTEGOP                  15                  2        17               15           2               -              0             2
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F5PCD10108           CCS REMEDY TESTING                                     CUSEGXTX                   0                  0         1                1           -               -              -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F5PCEDIVER           DIVERSITY TRAINING                                     DIRCTESI                   -                  -         -                -           -               -              -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F5PCMCMSCL           PASSPORT- SC MATERIALS MANAGEM                         SCMATRAN                 257                 31       288              245          43             (43)             -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F5PCZCDEPT           SUPERVISION & SUPPORT - CORPOR                         LBRCORPT                   4                  -         4                4           0               -              -             0
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F5PCZCONOP           CONTRIBUTION OPERATIONS - BELO                         ASSTSALL                   1                  0         1                1           0               -             (0)            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F5PCZECDEV           ECONOMIC DEVELOPMENT - BELOW T                         CUSEOPCO                   2                  0         2                1           0               -             (0)            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F5PCZFDSER           DESKTOP SERVICES                                       PCNUMALL                  15                  1        16               16           1               -              0             1
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F5PPD10154           MDT Wireless Telecom Serv                              CUSTEGOP                 286                 34       321              276          44               -              1            45
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F5PPD10156           Dist. Work Mgmt - DriveCam Sup                         CUSTELLA                   5                  1         5                5           -               -              -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F5PPD10162           Util Ops Cust Data Warehouse S                         CUSTEGOP                  45                  5        50               43           7               -              0             7
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              CPOP8       F5PPFALCON           Project Falcon                                         DIRECTNI                (358)                 -      (358)            (358)          -               -              -             -

                            Amounts may not add or tie to other schedules due to rounding.
                                                                                                                                                                                                                                                                                                                   EXHIBIT JFD-C
                                                                                                                                                                                         Domino, Joe                                                                                                                 Page 5 of 11
                                                                                                                                                                             ENTERGY TEXAS, INC.                                                                                                                             EXHIBIT JFD-C
2011 ETI Rate Case




                                                                                                                                                        Affiliate Billings - by Witness, Class, Department and Project                                                                                                    2011 TX Rate Case
                                                                                                                                                                  For the Twelve Months Ended June 30, 2011                                                                                                                     Page 6 of 11
                                                                                                                                                                               Amounts in Dollars
                                                                                                                                                                                           (A)              (B)               (C)              (D)          (E)            (F)              (G)             (H)
                                                                                                                                                                                                        Total Billings
                                                                                             Activity / Project                                                          ESI BIlling                   Service Company                                     ETI Per                       Pro Forma        Total ETI
                                       Class                    Billing Entity   Dept              Code                            Activity / Project Description         Method          Support         Recipient           Total       All Other BU's   Books        Exclusions        Amount          Adjusted
                     UTILITY & EXECUTIVE MANAGEMENT             ESI            CPOP8         F5PPHREXEC           HR Executive Financial Counsel                       ASSTSALL               7,102                   -          7,102            6,380          722               -            (722)                 -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI            CPOP8         F5PPSPE044           PMO Support Initiative-System-                       LOADOPCO               1,176                 129          1,305            1,088          217               -            (217)                 -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI            CPOP8         SAPCP25910           PC&R OVERHEAD POOL CHARGES                           CEAOUTAL                   0                   -              0                0            0              (0)              -                  -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CPOP8          Total                                                                                        5,517,075            167,988       5,685,063       5,117,844      567,219              (45)      (217,446)        349,728

                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CSODW          E1PCR56025           CUSTOM SALES & SERVICE UNIT- M                       DIRCTELI                  688                     -          688              688            -                -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI           CSODW          Total                                                                                               688                     -          688              688            -                -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI           FN086          E1PCR56226           Sales & Mktg - ALL JURIS                             MACCTALL               8,197                920           9,118           7,935        1,183                  -              20        1,202
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           FN086          F3PCCPM001           CORPORATE PERFORMANCE MANAGEME                       ASSTSALL           1,194,449            142,420       1,336,870       1,205,015      131,855                  -             (74)     131,781
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           FN086          F3PCF07300           CORP PLANNING & ANALYSIS- REGU                       CUSTEGOP                 479                 74             553             477           76                  -               1           77
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           FN086          F3PCFACALL           FACILITIES SVCS- ALL COS                             SQFTALLC                   -                  -               -               -            -                  -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           FN086          F3PP1E2EPM           End-to-End Process Mgmnt                             LVLSVCAL                   -                  -               -               -            -                  -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           FN086          F3PPCPMUTL           CORPORATE PERFORMANCE MGMT UTL                       EMPXRTNC              19,531              1,594          21,126          19,133        1,992                  -              40        2,032
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           FN086          F3PPHRTFMN           HR Transformation - O&M Costs                        EMPLOYAL                 819                 61             880             837           43                  -               1           44
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           FN086          F3PPTDERSD           MISO Transition ALL OPCO                             LOADOPCO                 905                111           1,016             847          169                  -            (169)           -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           FN086          F5PCF96930           BENCHMARKING PHASE II                                LOADWEOI               4,020                551           4,571           3,817          754                  -              16          770
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           FN086          F5PCZCDEPT           SUPERVISION & SUPPORT - CORPOR                       LBRCORPT                  28                  -              28              27            1                  -               -            1
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           FN086          F5PPERG100           Systemwide Ergonomics Initiati                       EMPLOYAL                   -                  -               -               -            -                  -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           FN086          F5PPSPE044           PMO Support Initiative-System-                       LOADOPCO                 278                 38             317             264           53                  -             (53)           -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           FN086          F5PPTHMPSN           Norwood Thompson Park Playgrou                       DIRCTETR               3,514                465           3,980           3,980            -                  -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           FN086          F5PPZUWELL           Entergy Wellness Program                             EMPLOYAL                 999                 87           1,086           1,033           53                  -               1           54

                     UTILITY & EXECUTIVE MANAGEMENT             ESI           FN086          Total                                                                                        1,233,220            146,323       1,379,544       1,243,365      136,178                  -            (218)     135,961

                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAF6G          F3PCZGASAG           GAS ADMINISTRATIVE                                   CUSGOPCO               1,183                      -      1,183            1,183              -                -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAF6G          Total                                                                                            1,183                      -      1,183            1,183              -                -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAF6P                                                                                                             80                   -             80               80             -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAF6P          F3PCG10345           GAS DIVISION DIRECTOR - ENOI E                       DIRCTENO             43,653               3,334         46,987           46,987             -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAF6P          F3PCG10347           GAS DIVISION DIRECTOR - EGSI E                       DIRECTLG             13,465                   -         13,465           13,465             -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAF6P          F3PCZGASAG           GAS ADMINISTRATIVE                                   CUSGOPCO              7,610                   -          7,610            7,610             -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAF6P          F5PCSAFTEG           SAFTEY TRAINING LOADER GAS CUS                       CUSGOPCO             10,786                 739         11,525           11,525             -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAF6P          F5PCZZ4070           IMPACT AWARDS                                        DIRCTESI                215                   -            215              215             -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAF6P          F5PPD10154           MDT Wireless Telecom Serv                            CUSTEGOP                525                   -            525              452            73                 -             (73)               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAF6P          F5PPZUWELL           Entergy Wellness Program                             EMPLOYAL                  -                   -              -                -             -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAF6P          SGPCG59006           GAS DISTRIBUTION ENOI O/H GAS                        DIRCTENO            240,285              28,421        268,706          268,706             -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAF6P          SGPCR79008           GAS DISTRIBUTION EGSI O/H-CHAR                       DIRECTLG            113,137              13,677        126,814          126,814             -                 -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAF6P          Total                                                                                         429,757              46,171        475,927          475,855            73                 -             (73)               -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAFH6                                                                                                              -                   -              -                -             -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAFH6          F3PCDG0004           OPERATOR QUAL DEVELOP & TRAIN                        DIRCTENO                226                   -            226              226             -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAFH6          F3PCFACALL           FACILITIES SVCS- ALL COS                             SQFTALLC                 98                   -             98               87            11                 -             (11)               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAFH6          F3PCFAPWHS           POWERHOUSE OPERATIONS                                EMPLOYAL                123                   -            123              117             6                 -              (6)               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAFH6          F3PCG10345           GAS DIVISION DIRECTOR - ENOI E                       DIRCTENO            455,541              48,381        503,922          503,922             -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAFH6          F3PCG10347           GAS DIVISION DIRECTOR - EGSI E                       DIRECTLG            446,592              47,126        493,718          493,718             -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAFH6          F3PCZGASAG           GAS ADMINISTRATIVE                                   CUSGOPCO                 25                   -             25               25             -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAFH6          F5PCSAFTEG           SAFTEY TRAINING LOADER GAS CUS                       CUSGOPCO              5,570                 806          6,376            6,376             -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAFH6          F5PCSVCAWD           SERVICE AWARDS                                       DIRCTESI              1,060                   -          1,060            1,060             -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAFH6          F5PCZCDEPT           SUPERVISION & SUPPORT - CORPOR                       LBRCORPT                318                   -            318              305            13                 -             (13)               -
3-58




                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAFH6          F5PPZUWELL           Entergy Wellness Program                             EMPLOYAL                427                  43            470              447            23                 -             (23)               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAFH6          SGPCG59006           GAS DISTRIBUTION ENOI O/H GAS                        DIRCTENO             42,644               5,218         47,862           47,862             -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAFH6          SGPCR79008           GAS DISTRIBUTION EGSI O/H-CHAR                       DIRECTLG             42,510               5,202         47,713           47,713             -                 -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAFH6          Total                                                                                         995,135             106,776       1,101,911       1,101,858            53                 -             (53)               -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAG2E          C5PP449606           Gas Serv Storm Rebuild Replace                       DIRCTENO             36,405               4,363         40,768           40,768              -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAG2E          F3PCFACALL           FACILITIES SVCS- ALL COS                             SQFTALLC                934                   -            934              831            104                -            (104)               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAG2E          F3PCG10345           GAS DIVISION DIRECTOR - ENOI E                       DIRCTENO             56,490               4,045         60,535           60,535              -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAG2E          F3PCG10347           GAS DIVISION DIRECTOR - EGSI E                       DIRECTLG             47,226               4,429         51,654           51,654              -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAG2E          F3PCZGASAG           GAS ADMINISTRATIVE                                   CUSGOPCO            190,744              19,573        210,317          210,317              -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAG2E          F3PPAMPDEV           Advanced Mgmt Dev Program                            EMPLOYAL                  -                   -              -                -              -                -               -                -

                            Amounts may not add or tie to other schedules due to rounding.
                                                                                                                                                                                                                                                                                                                             EXHIBIT JFD-C
                                                                                                                                                                                       Domino, Joe                                                                                                                             Page 6 of 11
                                                                                                                                                                             ENTERGY TEXAS, INC.                                                                                                                      EXHIBIT JFD-C
2011 ETI Rate Case




                                                                                                                                                        Affiliate Billings - by Witness, Class, Department and Project                                                                                             2011 TX Rate Case
                                                                                                                                                                  For the Twelve Months Ended June 30, 2011                                                                                                              Page 7 of 11
                                                                                                                                                                               Amounts in Dollars
                                                                                                                                                                                           (A)             (B)          (C)            (D)          (E)             (F)              (G)             (H)
                                                                                                                                                                                                       Total Billings
                                                                                             Activity / Project                                                          ESI BIlling                  Service Company                              ETI Per                        Pro Forma        Total ETI
                                       Class                    Billing Entity     Dept            Code                            Activity / Project Description         Method          Support        Recipient      Total     All Other BU's   Books         Exclusions        Amount          Adjusted
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG2E       F4PPENG134           Mutual Assist ENOI Gas NMGC 2/                       DIRCTENO                 138                17       154             154              -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG2E       F5PCDG0168           GAS EMPLOYEE DEVELOPMENT PROGR                       CUSGOPCO                  19                 -        19              19              -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG2E       F5PCSAFTEG           SAFTEY TRAINING LOADER GAS CUS                       CUSGOPCO              33,725             1,205    34,930          34,930              -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG2E       F5PCSVCAWD           SERVICE AWARDS                                       DIRCTESI                 285                 -       285             285              -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG2E       F5PPGEFBUS           Gas Operations Efficient Busin                       CUSGOPCO              45,084             5,479    50,562          50,562              -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG2E       SDPCT30070           CAPITAL SUSPENSE, DISTR WIRES,                       DIRCTELI                 676                75       751             751              -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG2E       SGPCG59006           GAS DISTRIBUTION ENOI O/H GAS                        DIRCTENO              69,440             8,391    77,830          77,830              -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG2E       SGPCR79008           GAS DISTRIBUTION EGSI O/H-CHAR                       DIRECTLG              69,433             8,390    77,823          77,823              -                -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG2E       Total                                                                                         550,596             55,966   606,562        606,458            104                 -            (104)               -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG2U       F3PCFACALL           FACILITIES SVCS- ALL COS                             SQFTALLC                930                  -       930            827            103                 -            (103)               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG2U       F3PCG10345           GAS DIVISION DIRECTOR - ENOI E                       DIRCTENO             44,059              4,862    48,922         48,922              -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG2U       F3PCG10347           GAS DIVISION DIRECTOR - EGSI E                       DIRECTLG             41,423              4,773    46,196         46,196              -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG2U       F3PCZGASAG           GAS ADMINISTRATIVE                                   CUSGOPCO             82,739              9,065    91,804         91,804              -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG2U       F4PPEGS148           Mutual Assist EGSL GAS NMGC 2/                       DIRECTLG                829                100       929            929              -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG2U       F4PPENG134           Mutual Assist ENOI Gas NMGC 2/                       DIRCTENO                829                100       929            929              -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG2U       F5PCSAFTEG           SAFTEY TRAINING LOADER GAS CUS                       CUSGOPCO              6,872                775     7,647          7,647              -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG2U       F5PCSVCAWD           SERVICE AWARDS                                       DIRCTESI                269                  -       269            269              -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG2U       F5PPZUWELL           Entergy Wellness Program                             EMPLOYAL                439                 45       484            460             24                 -             (24)               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG2U       SGPCG59006           GAS DISTRIBUTION ENOI O/H GAS                        DIRCTENO             57,962              6,941    64,902         64,902              -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG2U       SGPCR79008           GAS DISTRIBUTION EGSI O/H-CHAR                       DIRECTLG             60,438              7,218    67,656         67,656              -                 -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG2U       Total                                                                                         296,789             33,879   330,668        330,541            127                 -            (127)               -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG7F       F3PCCDVETR           CORP DEV-ANALYSIS STRATEGIC ME                       ASSTSALL                  -                  -         -              -              -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG7F       F3PCG10345           GAS DIVISION DIRECTOR - ENOI E                       DIRCTENO             85,531              9,803    95,334         95,334              -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG7F       F3PCZGASAG           GAS ADMINISTRATIVE                                   CUSGOPCO              5,877                  -     5,877          5,877              -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG7F       F3PPAMPDEV           Advanced Mgmt Dev Program                            EMPLOYAL              4,112                  -     4,112          3,921            192                 -            (192)               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG7F       F5PCSAFTEG           SAFTEY TRAINING LOADER GAS CUS                       CUSGOPCO             17,545              1,247    18,792         18,792              -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG7F       SGPCG59006           GAS DISTRIBUTION ENOI O/H GAS                        DIRCTENO            113,573             13,702   127,275        127,275              -                 -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAG7F       Total                                                                                         226,639             24,752   251,391        251,199            192                 -            (192)               -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAH2H       F3PCDG0004           OPERATOR QUAL DEVELOP & TRAIN                        DIRCTENO             22,082              2,217    24,299         24,299               -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAH2H       F3PCDG0005           OPERATOR QUAL DEVELOP & TRAIN                        DIRECTLG             84,690              8,908    93,598         93,598               -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAH2H       F3PCG10347           GAS DIVISION DIRECTOR - EGSI E                       DIRECTLG              3,585                678     4,264          4,264               -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAH2H       F3PCZGASAG           GAS ADMINISTRATIVE                                   CUSGOPCO              2,794                  -     2,794          2,794               -                -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAH2H       Total                                                                                         113,151             11,803   124,955        124,955               -                -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAJ2J       C7PPSJ3198           EMI Storm Distr Ops 1/7/11Wint                       DIRCTEMI              1,060                196     1,256          1,256               -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAJ2J       F3PCG10345           GAS DIVISION DIRECTOR - ENOI E                       DIRCTENO                  -                  -         -              -               -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAJ2J       F3PCZGASAG           GAS ADMINISTRATIVE                                   CUSGOPCO            130,972             13,473   144,445        144,445               -                -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAJ2J       Total                                                                                         132,031             13,670   145,701        145,701               -                -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAJ2K       C5PC449602           GAS FAILURES BLANKET                                 DIRCTENO             35,953                  -    35,953         35,953             -                  -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAJ2K       C7PPSJ2462           STORM DMG LA DIST ELL 1/8/11 I                       DIRCTELI                153                 28       181            181             -                  -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAJ2K       F3PCDG0004           OPERATOR QUAL DEVELOP & TRAIN                        DIRCTENO              4,811                  -     4,811          4,811             -                  -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAJ2K       F3PCDG0005           OPERATOR QUAL DEVELOP & TRAIN                        DIRECTLG              4,811                  -     4,811          4,811             -                  -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAJ2K       F3PCFACALL           FACILITIES SVCS- ALL COS                             SQFTALLC                 94                  -        94             84            10                  -             (10)               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAJ2K       F3PCG10345           GAS DIVISION DIRECTOR - ENOI E                       DIRCTENO                415                  -       415            415             -                  -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAJ2K       F3PCG10347           GAS DIVISION DIRECTOR - EGSI E                       DIRECTLG                415                  -       415            415             -                  -               -                -
3-59




                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAJ2K       F3PCZGASAG           GAS ADMINISTRATIVE                                   CUSGOPCO            149,109             14,184   163,294        163,294             -                  -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAJ2K       F5PCSAFTEG           SAFTEY TRAINING LOADER GAS CUS                       CUSGOPCO              2,739                 98     2,837          2,837             -                  -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAJ2K       F5PCSVCAWD           SERVICE AWARDS                                       DIRCTESI                369                  -       369            369             -                  -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAJ2K       SGPCG59006           GAS DISTRIBUTION ENOI O/H GAS                        DIRCTENO             26,092              3,146    29,238         29,238             -                  -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAJ2K       SGPCR79008           GAS DISTRIBUTION EGSI O/H-CHAR                       DIRECTLG              3,499                419     3,918          3,918             -                  -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAJ2K       Total                                                                                         228,461             17,876   246,337        246,326            10                  -             (10)               -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAJ3K       C5PP449606           Gas Serv Storm Rebuild Replace                       DIRCTENO             72,953              8,794    81,747         81,747               -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAJ3K       F3PCCDVCCN           PROJECT GUMBO                                        CUSGOPCO                  -                  -         -              -               -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAJ3K       F3PCZGASAG           GAS ADMINISTRATIVE                                   CUSGOPCO             31,354              3,770    35,124         35,124               -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              GAJ3K       F5PCSAFTEG           SAFTEY TRAINING LOADER GAS CUS                       CUSGOPCO              1,274                161     1,435          1,435               -                -               -                -

                            Amounts may not add or tie to other schedules due to rounding.
                                                                                                                                                                                                                                                                                                                      EXHIBIT JFD-C
                                                                                                                                                                                       Domino, Joe                                                                                                                      Page 7 of 11
                                                                                                                                                                             ENTERGY TEXAS, INC.                                                                                                                          EXHIBIT JFD-C
2011 ETI Rate Case




                                                                                                                                                        Affiliate Billings - by Witness, Class, Department and Project                                                                                                 2011 TX Rate Case
                                                                                                                                                                  For the Twelve Months Ended June 30, 2011                                                                                                                  Page 8 of 11
                                                                                                                                                                               Amounts in Dollars
                                                                                                                                                                                            (A)             (B)           (C)              (D)          (E)             (F)              (G)             (H)
                                                                                                                                                                                                        Total Billings
                                                                                             Activity / Project                                                          ESI BIlling                   Service Company                                 ETI Per                        Pro Forma        Total ETI
                                       Class                    Billing Entity   Dept              Code                            Activity / Project Description         Method          Support         Recipient       Total       All Other BU's   Books         Exclusions        Amount          Adjusted
                     UTILITY & EXECUTIVE MANAGEMENT             ESI            GAJ3K         F5PCSVCAWD           SERVICE AWARDS                                       DIRCTESI                   -                  -          -                 -              -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI            GAJ3K         SGPCG59006           GAS DISTRIBUTION ENOI O/H GAS                        DIRCTENO              51,505              6,205     57,711            57,711              -                -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI            GAJ3K         SGPCR79008           GAS DISTRIBUTION EGSI O/H-CHAR                       DIRECTLG              51,505              6,205     57,710            57,710              -                -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI           GAJ3K          Total                                                                                         208,592              25,135    233,726          233,726               -                -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SGG2D          E1PCR56226           Sales & Mktg - ALL JURIS                             MACCTALL                294                  36        330              287             43                 -             (43)               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SGG2D          F3PCCDVCCN           PROJECT GUMBO                                        CUSGOPCO                  -                   -          -                -              -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SGG2D          F3PCFACALL           FACILITIES SVCS- ALL COS                             SQFTALLC              1,975                   -      1,975            1,759            216                 -            (216)               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SGG2D          F3PCG10345           GAS DIVISION DIRECTOR - ENOI E                       DIRCTENO                786                   -        786              786              -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SGG2D          F3PCG10347           GAS DIVISION DIRECTOR - EGSI E                       DIRECTLG                 28                   -         28               28              -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SGG2D          F3PCSYSRAS           SYSTEM REGULATORY AFFAIRS-STAT                       CUSTEGOP                 62                   8         70               60             10                 -             (10)               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SGG2D          F3PCZGASAG           GAS ADMINISTRATIVE                                   CUSGOPCO            517,556              59,411    576,967          576,967              -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SGG2D          F3PPE9974S           Utl ECI Continuing Improve ESI                       CUSEOPCO                552                  68        620              529             92                 -             (92)               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SGG2D          F3PPENOFRP           ENO Annual FRP Filing 2010-12                        DIRCTENO              2,739                 312      3,051            3,051              -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SGG2D          F3PPGRSP10           EGSL RATE STABLIZATN (TY 2009/                       DIRECTLG                 88                  10         98               98              -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SGG2D          F3PPPGA010           PGA Audit 2010                                       DIRECTLG                430                  50        480              480              -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SGG2D          F5PCSAFTEG           SAFTEY TRAINING LOADER GAS CUS                       CUSGOPCO              3,545                 452      3,997            3,997              -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SGG2D          F5PCSVCAWD           SERVICE AWARDS                                       DIRCTESI                 98                   -         98               98              -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SGG2D          F5PCZCDEPT           SUPERVISION & SUPPORT - CORPOR                       LBRCORPT                211                   -        211              205              6                 -              (6)               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SGG2D          F5PPHREXEC           HR Executive Financial Counsel                       ASSTSALL              3,500                   -      3,500            3,144            356                 -            (356)               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SGG2D          SGPCG59006           GAS DISTRIBUTION ENOI O/H GAS                        DIRCTENO            112,081              13,617    125,697          125,697              -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SGG2D          SGPCR79008           GAS DISTRIBUTION EGSI O/H-CHAR                       DIRECTLG            112,048              13,613    125,661          125,661              -                 -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SGG2D          Total                                                                                         755,995              87,575    843,570          842,847            723                 -            (723)               -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          C1PPFI5207           Payroll Time & Labor - Phase I                       EMPLOYAL                  (0)                 -          (0)             (0)          (0)                 0             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          C1PPHR8800           PS HCM (Human Cap Mgmt) Upgrd                        EMPLOYAL                  (0)                 -          (0)             (0)           -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          C6PPAMBSGN           AMI:BASE Non-Incremental, EGSL                       DIRECTLG                  (1)                 -          (1)             (1)           -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PC6H0026           NORTHEAST MGMT OVERSITE IP2/IP                       SPL77N7A                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCCPM001           CORPORATE PERFORMANCE MANAGEME                       ASSTSALL                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCD10006           FIELD DEVELOPMENT                                    CUSTEGOP                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCD10049           REGULATED RETAIL SYSTEMS - O&M                       CUSTEGOP                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCD10077           REGULATORY AFFAIRS WORLDOX IMP                       DIRCTENO                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCD10105           CUSTOMER CARE SYSTEM SUPPORT                         CUSEGXTX                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCE99750           PRES- ENT. LA-GEN'L OPS-ELI/EG                       CUSELGLA                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCE99795           GROUP PRES - UTILITY OPERATION                       CUSTEGOP           1,997,434            130,481   2,127,915       1,833,530      294,385               (373)       (3,718)        290,294
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCF10414           ESI TAX SERVICES                                     LVLSVCAL                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCF23425           ACCOUNTS PAYABLE PROCESSING                          APTRNALL                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCF23428           TREASURY SYSTEMS                                     BNKACCTA                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCF23442           PAYROLL PROCESSING                                   PRCHKALL                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCF26910           REVENUE ACCOUNTING ANALYSIS                          CUSEGALL                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCF72271           DATA WAREHOUSE                                       GENLEDAL                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCF72670           GENERAL ACCOUNTING SYSTEM MAIN                       GENLEDAL                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCF72901           MOBILE DATA TERMINAL BASELOAD                        CUSTEGOP                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCF73027           BUDGET SYSTEM MAINTENANCE                            GENLEDAL                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCF73901           AM/FM BASELOAD (SUPPORT)                             DIRECTTX                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCF74195           TRANSMISSION APPLICATION SUPPO                       TRSBLNOP                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCF74344           GENERATION PLANNING & DISPATCH                       LOADOPCO                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCF74515           FOSSIL MAINTENANCE MANAGEMENT                        CAPAOPCO                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCF74585           FOSSIL APPLICATION SUPPORT                           CAPAOPCO                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCF99182           RECORDS MANAGEMENT                                   RECDMGNT                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCFCQEAI           ENTERPRISE APPLICATION INTEGRA                       APPSUPAL                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCFCQEXC           EXCHANGE                                             PCNUMALL                   -                  -           -               -            -                  -             -               -
3-60




                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCFCQMVS           MAINFRAME                                            APPSMVSX                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCFCQNTS           NT SERVERS                                           APPSWINT                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCFCQUNX           UNIX SERVERS                                         APPSUNIX                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCFX2815           EDMS PRODUCT LINE SUPPORT                            EMPLOYAL                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCFX3275           WEB INFRASTRUCTURE MAINTENANCE                       PCNUMALL                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCFX3290           IT BUSINESS PLANNING AND GOVER                       ITSPENDA                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCFX3350           A/R & BILLING SUPPORT                                ARTRNALL                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCFX3625           SUPPLY CHAIN - CDW SYSTEMS SUP                       SCDSPALL                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCFX3640           WHITE AMBER & ITILITI SUPPORT                        SCMATRAN                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCFX3650           WEB PAGE SUPPORT - CORPORATE                         EMPLOYAL                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCFX3670           CORPORATE COMMUNICATIONS WEB S                       DIRCTETR                   -                  -           -               -            -                  -             -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI           SU084          F3PCFX3690           PEARL SUPPORT                                        APTRNALL                   -                  -           -               -            -                  -             -               -

                            Amounts may not add or tie to other schedules due to rounding.
                                                                                                                                                                                                                                                                                                                          EXHIBIT JFD-C
                                                                                                                                                                                       Domino, Joe                                                                                                                          Page 8 of 11
                                                                                                                                                                              ENTERGY TEXAS, INC.                                                                                                              EXHIBIT JFD-C
2011 ETI Rate Case




                                                                                                                                                         Affiliate Billings - by Witness, Class, Department and Project                                                                                     2011 TX Rate Case
                                                                                                                                                                   For the Twelve Months Ended June 30, 2011                                                                                                      Page 9 of 11
                                                                                                                                                                                Amounts in Dollars
                                                                                                                                                                                             (A)           (B)          (C)            (D)          (E)          (F)              (G)             (H)
                                                                                                                                                                                                       Total Billings
                                                                                             Activity / Project                                                           ESI BIlling                 Service Company                              ETI Per                     Pro Forma        Total ETI
                                       Class                    Billing Entity      Dept           Code                             Activity / Project Description         Method          Support       Recipient      Total     All Other BU's   Books      Exclusions        Amount          Adjusted
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCFX3790           ESTER SUPPORT                                         PRCHKALL                  0                 -         0               0           0                -               -            0
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCFX5555           DATA WAREHOUSE TOOLS SUPPORT                          APPSUPAL                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCHRCALL           HR SVCS- CUST SERV SUPT- ALL C                        EMPLOCSS                196                 -       196             181          15                -               -           15
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCHRDCSS           HR- FRANCHISE OPNS (DIST) SUPT                        EMPLFRAN                481                 -       481             414          66                -               -           66
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCHRPRES           HR PRESIDENT/ CEO SUPPORT- ALL                        EMPLPRES                  7                 -         7               6           1                -               -            1
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCHRSALL           HR SERVICES- ALL COMPANIES                            EMPLOYAL                  0                 -         0               0           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCHRSDUT           HR SVCS - ESI DOMESTIC UTILITY                        DIRCTESI                  8                 -         8               8           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCMCMSOM           MATERIALS & CONTRACTS MGTMT SY                        SCMATXNU                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCN20520           WORK MANAGEMENT SYSTEM (WMS) M                        DIRCTEOI                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCN20521           IDEAS MAINTENANCE                                     DIRCTEOI                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCN20522           PCRS MAINTENANCE                                      DIRCTEOI                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCN20527           NUCLEAR IT QUICK RESPONSE TEAM                        DIRCTEOI                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCN20528           ERD SUPPORT (MAINTENANCE)                             DIRCTEOI                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCR40118           UTILITY COMMUNICATIONS                                CUSTEGOP             83,560                 -    83,560          72,040      11,521                -            (118)      11,403
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCR40430           EMPLOYEE COMM (REGULATED COMPA                        EMPLOREG             71,944                 -    71,944          67,408       4,535                -               -        4,535
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCR40500           EMPLOYEE COMM (REG + UNREG COM                        EMPLOYAL                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCR53291           ESI REMITTANCE PROCESSING                             CUSEOPCO                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCR73326           CUSTOMER SERVICE CENTER SUPPOR                        CUSTCALL                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCR73380           CREDIT SYSTEMS                                        CUSTEGOP                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCRM1021           AUDIT: ESI INFORMATION TECHNO                         DIRCTESI                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCSYSAGR           SYSTEM AGREEMENT-2001                                 CUSEOPCO            770,707                 -   770,707         656,959     113,747                -               -      113,747
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCWE0063           EMO APPLICATION SUPPORT                               LOADOPCO                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCWE0187           FOSSIL IT SUPPORT FOR 2003-200                        CAPAOPCO                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PCWS0327           SAIC LABOR CHARGES TO PMDC                            CAPAOPCO                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PP6HHOST           ENNE Hosting/server support/SO                        DIRCTENU                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PP6HINDS           Indus Passport                                        DIRCTENU                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPAMISTG           AMI Strategy Expense                                  CUSEOPCO                  1                 -         1               1           0                -               -            0
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPD10115           Dist Work Mgmt O&M-DIS/DSS/ADS                        CUSTEGOP                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPD10119           Dist Work Mgmt O&M-CTS Contrac                        CUSTEGOP                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPD10120           Dist Oper Appl O&M-AM/FM Suppo                        CUSTEGOP                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPD10121           Dist Oper Appl O&M-AutoCAD                            CUSEOPCO                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPD10123           Dist Oper Appl O&M-EPO&SAISO S                        CUSEOPCO                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPD10124           Dist Oper Appl O&M-PDD/ECOS Sp                        CUSTEGOP                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPD10128           ARCS/Itron/MV90 Support                               CUSTEGOP                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPD10129           Billing Determinate Proc/Major                        CUSTEGOP                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPD10130           Customer Care System Interface                        CUSEGXTX                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPD10131           CIS/AIS & Core Support                                DIRECTTX                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPD10132           Electronic Data Interchange Su                        CUSEOPCO                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPD10133           Internet Bill Presentment & Pm                        CUSEGXTX                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPD10134           MAB Load Research Support                             CUSTEGOP                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPD10137           Bill Delivery Support                                 CUSEGXTX                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPD10140           Large Power Billing System for                        CUSEOPCO                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPD10141           CIMS Support                                          CUSEGXTX                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPD10142           Customer Service Field Applica                        CUSTEGOP                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPD10146           Dist Work Mgmt-Cyndrus Support                        VEHCLALL                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPD10150           TaxWare Support                                       CUSTEGOP                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPD10158           CCS Agent Care System                                 CUSEGXTX                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPD10161           ePlus (Web Self Service) Suppo                        CUSTEGOP                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPE9974S           Utl ECI Continuing Improve ESI                        CUSEOPCO             11,356                 -    11,356           9,682       1,674                -               -        1,674
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPETEGSL           Executive Timesheets- EGSL                            DIRECTLG              2,215               216     2,430           2,430           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPETENOI           Executive Timesheet- ENOI                             DIRCTENO             55,980             1,967    57,948          57,948           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPETSEAI           Executives Time and Expenses-E                        DIRCTEAI             35,047             3,609    38,656          38,656           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPETSELI           Executive Timesheets- ELI                             DIRCTELI             77,575             2,603    80,178          80,178           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPETSEMI           Executive Timesheets- EMI                             DIRCTEMI             17,613             1,500    19,113          19,113           -                -               -            -
3-61




                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPETSETI           Executive Time and Expenses-ET                        DIRECTTX             29,110             2,869    31,979               -      31,979                -             601       32,580
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPF72700           Cognos Reporting Support                              GENLEDAL                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPFX5307           Compliance Software System Sup                        ASSTSALL                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPFXOPMO           IT Enterprise Program Manageme                        ITSPENDA                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPN20535           P3E Scheduling Software Mainte                        DIRCTEOI                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPN20536           INDUS Software Maintenance                            DIRCTEOI                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F3PPPMUPGR           Performance Management Sys Upg                        CUSEOPCO                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F5PCD10093           WEB DEVELOPMENT SUPPORT                               CUSTEGOP                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F5PCLIHPPC           CONSUMER EDUCATION PROGRAMS                           CUSEOPCO                  3                 -         3               3           1                -               -            1
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F5PCMCMSCL           PASSPORT- SC MATERIALS MANAGEM                        SCMATRAN                  -                 -         -               -           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F5PCSVCAWD           SERVICE AWARDS                                        DIRCTESI                131                 -       131             131           -                -               -            -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F5PCZCDEPT           SUPERVISION & SUPPORT - CORPOR                        LBRCORPT                 60                 -        60              59           2                -               -            2

                            Amounts may not add or tie to other schedules due to rounding.
                                                                                                                                                                                                                                                                                                               EXHIBIT JFD-C
                                                                                                                                                                                        Domino, Joe                                                                                                              Page 9 of 11
                                                                                                                                                                             ENTERGY TEXAS, INC.                                                                                                                               EXHIBIT JFD-C
2011 ETI Rate Case




                                                                                                                                                        Affiliate Billings - by Witness, Class, Department and Project                                                                                                      2011 TX Rate Case
                                                                                                                                                                  For the Twelve Months Ended June 30, 2011                                                                                                                      Page 10 of 11
                                                                                                                                                                               Amounts in Dollars
                                                                                                                                                                                            (A)              (B)               (C)              (D)          (E)             (F)              (G)             (H)
                                                                                                                                                                                                         Total Billings
                                                                                             Activity / Project                                                          ESI BIlling                    Service Company                                     ETI Per                        Pro Forma        Total ETI
                                       Class                    Billing Entity      Dept           Code                            Activity / Project Description         Method          Support          Recipient           Total       All Other BU's   Books         Exclusions        Amount          Adjusted
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F5PCZCONOP           CONTRIBUTION OPERATIONS - BELO                       ASSTSALL                   -                       -          -                 -             -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F5PCZFDSER           DESKTOP SERVICES                                     PCNUMALL                   -                       -          -                 -             -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F5PP10011U           Show Cause Docket No. 10-011-U                       DIRCTEAI              78,782                       -     78,782            78,782             -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F5PPD10154           MDT Wireless Telecom Serv                            CUSTEGOP                   -                       -          -                 -             -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F5PPD10156           Dist. Work Mgmt - DriveCam Sup                       CUSTELLA                   -                       -          -                 -             -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F5PPD10162           Util Ops Cust Data Warehouse S                       CUSTEGOP                   -                       -          -                 -             -                 -               -                -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F5PPHREXEC           HR Executive Financial Counsel                       ASSTSALL               7,227                       -      7,227             6,495           733                 -            (733)               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       F5PPSUPICT           Support of ICT                                       LOADOPCO                   -                       -          -                 -             -                 -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU084       Total                                                                                        3,239,437             143,246       3,382,683       2,924,024      458,659               (373)       (3,967)        454,318

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU085       F3PCE99795           GROUP PRES - UTILITY OPERATION                       CUSTEGOP                     -                     -            -               -              -                -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SU085       Total                                                                                                  -                     -            -               -              -                -               -                -

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       C1PPFIRGTL           Regulated Time-LBR & Absence M                       EMPOPCPE              1,786                  246          2,032            1,853          179            (179)               -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       C7PPSJ1214           WINTER STORM DL EAI DIST 01/26                       DIRCTEAI                  -                    -              -                -            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       C7PPSJ1250           STORM DL EAI DIST 4/19/11-4/24                       DIRCTEAI              2,890                  433          3,323            3,323            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       C7PPSJ1251           TORNADOES DL EAI DIST 4/25/11                        DIRCTEAI              5,554                  861          6,416            6,416            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       C7PPSJ2474           STORM Dmg ELL 4/25 to 4/27/11                        DIRCTELI                100                   12            112              112            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       C7PPSJ3183           EMI 04/24/10 Tornadoes Distr O                       DIRCTEMI                  -                    -              -                -            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       C7PPSJ3198           EMI Storm Distr Ops 1/7/11Wint                       DIRCTEMI             18,147                2,392         20,539           20,539            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       C7PPSJ3204           EMI StormTornadoes DistrOps 4/                       DIRCTEMI                100                   12            112              112            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       C8PPTL5496           Replace Storm Damages                                DIRCTEAI             20,682                3,097         23,779           23,779            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       E2PPSJ1255           T-Grid Storm Tornadoes EAI 4/2                       DIRCTEAI                315                   44            359              359            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F3PCFACALL           FACILITIES SVCS- ALL COS                             SQFTALLC                172                    -            172              153           19               -                -              19
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F3PCFAPWHS           POWERHOUSE OPERATIONS                                EMPLOYAL                  -                    -              -                -            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F3PCT29320           SKILLS TRAINING CUST. SERV- HE                       CUSEOPCO                163                    -            163              139           24               -                -              24
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F3PCT29400           OPERATIONS SAFETY - HEADQUARTE                       CUSTEGOP            689,509               74,343        763,852          658,206      105,647             512            1,807         107,966
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F3PCT29406           OPERATIONS SAFETY - TEXAS DIST                       DIRECTTX             15,773                    -         15,773                -       15,773               -                -          15,773
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F3PCTDDS26           CUSTOMER SERVICE SUPPORT - O&M                       CUSTEGOP                120                    -            120              103           17               -                -              17
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F3PCTDS010           PROCESS & SKILLS TRAINING ADMI                       EMPLFRAN            120,567               14,007        134,574          115,628       18,946               -              389          19,335
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F3PCTDTR08           SKILLS TRAINING - LOUISIANA EL                       DIRCTELI                  -                    -              -                -            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F3PCTTDS12           TRANSMISSION LINES O&M EXPENS                        TRALINOP                  -                    -              -                -            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F3PCTTDS17           Substation Maintenance EGSI LA                       DIRECTLG              1,540                    -          1,540            1,540            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F3PCTTDS19           SUBSTATION/SYSTEM PROT MAINT -                       DIRCTEAI             10,322                    -         10,322           10,322            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F3PCTTDS21           SUBSTATION/SYSTEM PROT MAINT -                       DIRCTELI              1,540                    -          1,540            1,540            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F3PCTTDS22           SUBSTATION/SYSTEM PROT MAINT -                       DIRCTEMI              7,620                    -          7,620            7,620            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F3PCTTDS23           Substation Maintenance - Texas                       DIRECTTX             15,773                    -         15,773                -       15,773               -                -          15,773
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F3PCTTDS24           SUBSTATION/SYSTEM PROT MAINT -                       DIRCTENO              1,540                    -          1,540            1,540            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F3PCTTDS27           DISTRIBUTION O&M EXPENSE -EAI                        DIRCTEAI             13,605                    -         13,605           13,605            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F3PCTTDS28           DISTRIBUTION O&M EXPENSE -EMI                        DIRCTEMI             11,088                  376         11,464           11,464            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F3PCTTDS29           DISTRIBUTION O&M EXPENSE -ELI                        DIRCTELI              9,001                  708          9,709            9,709            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F3PCTTDS30           DISTRIBUTION O&M EXPENSE -EGSI                       DIRECTLG              1,540                    -          1,540            1,540            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F3PCTTDS31           DISTRIBUTION O&M EXPENSE - ENO                       DIRCTENO              1,596                    -          1,596            1,596            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F3PCTTDS38           TRANSMISSION O&M MGMT/SUPPORT                        TRSBLNOP                145                    -            145              128           17             (17)               -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F3PCTTDS71           TRANSMISSION MANAGEMENT/SUPPOR                       DIRCTEAI                  -                    -              -                -            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F5PCTTDS70           TRANS MAINTENANCE: LINES & SUB                       TRSBLNOP            475,946               54,604        530,550          468,094       62,456           4,130            1,099          67,685
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F5PPERG100           Systemwide Ergonomics Initiati                       EMPLOYAL              4,552                   85          4,638            4,414          224               -                1             224
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F5PPSAFTEL           SAFETY TRAINING LOADER ELEC LA                       CUSTELLA                698                   78            776              776            -               -                -               -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F5PPTVPPRO           Voluntary Protection Program                         TRSBLNOP                698                   78            776              685           91               -                2              93
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       F5PPZUWELL           Entergy Wellness Program                             EMPLOYAL              1,083                  109          1,192            1,134           58               -                1              59

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SULSY       Total                                                                                        1,434,169             151,485       1,585,654       1,366,430      219,224           4,446            3,300         226,970
3-62




                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SUUOS       F3PCE99795           GROUP PRES - UTILITY OPERATION                       CUSTEGOP              14,122                       -     14,122           12,175         1,947                  -               -         1,947

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SUUOS       Total                                                                                           14,122                       -     14,122           12,175         1,947                  -               -         1,947

                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SUUS1       F3PCFBLREG           BELOW THE LINE- REGULATED                            CUSTEGOP                  -                    -              -                -            -                   -               -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SUUS1       F3PCSYSRAS           SYSTEM REGULATORY AFFAIRS-STAT                       CUSTEGOP            105,229                    -        105,229           90,721       14,508                   -               -        14,508
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SUUS1       F3PPE9981A           Integrated Energy Mgmt EAI                           DIRCTEAI                  -                    -              -                -            -                   -               -             -
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SUUS1       F3PPE9981S           Integrated Energy Mgmt ESI                           CUSEOPCO             15,986                1,847         17,834           15,206        2,628                   -               8         2,636
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SUUS1       F5PCZU1573           REGULATORY AFFAIRS -- 100% EGS                       DIRECTTX             11,275                    -         11,275                -       11,275                   -               -        11,275
                     UTILITY & EXECUTIVE MANAGEMENT             ESI              SUUS1       F5PPETX009           2009 Texas Rate Case Support                         DIRECTTX                148                    -            148                -          148                   -            (148)            -


                            Amounts may not add or tie to other schedules due to rounding.
                                                                                                                                                                                                                                                                                                                               EXHIBIT JFD-C
                                                                                                                                                                                       Domino, Joe                                                                                                                              Page 10 of 11
                                                                                                                                                              ENTERGY TEXAS, INC.                                                                                                                  EXHIBIT JFD-C
2011 ETI Rate Case




                                                                                                                                         Affiliate Billings - by Witness, Class, Department and Project                                                                                         2011 TX Rate Case
                                                                                                                                                   For the Twelve Months Ended June 30, 2011                                                                                                         Page 11 of 11
                                                                                                                                                                Amounts in Dollars
                                                                                                                                                                            (A)             (B)            (C)             (D)          (E)           (F)              (G)           (H)
                                                                                                                                                                                        Total Billings
                                                                                               Activity / Project                                         ESI BIlling                  Service Company                                 ETI Per                      Pro Forma      Total ETI
                                         Class                    Billing Entity   Dept              Code           Activity / Project Description         Method          Support        Recipient        Total      All Other BU's   Books       Exclusions        Amount        Adjusted
                     UTILITY & EXECUTIVE MANAGEMENT               ESI            SUUS1         Total                                                                        132,639              1,847     134,487          105,927       28,560                -          (141)       28,420

                     UTILITY & EXECUTIVE MANAGEMENT               Total ESI                                                                                               28,688,315         2,014,250   30,702,565     28,491,933     2,210,631      (39,503)        (231,900)    1,939,228

                     Total UTILITY & EXECUTIVE MANAGEMENT                                                                                                                 28,688,315         2,014,250   30,702,565     28,491,933     2,210,631      (39,503)        (231,900)    1,939,228

                     Total Domino, Joe                                                                                                                                    28,688,315         2,014,250   30,702,565     28,491,933     2,210,631      (39,503)        (231,900)    1,939,228
3-63




                              Amounts may not add or tie to other schedules due to rounding.
                                                                                                                                                                                                                                                                                                   EXHIBIT JFD-C
                                                                                                                                                                        Domino, Joe                                                                                                                 Page 11 of 11
    This page has been intentionally left blank.




2011 ETI Rate Case                       3-64
                                                                                                                          ENTERGY TEXAS, INC.                                                                EXHIBIT JFD-D
2011 ETI Rate Case




                                                                                               Affiliate Billings - Pro Forma Summary - By Witness, Class, & Pro Forma                                    2011 TX Rate Case
                                                                                                                For the Twelve Months Ended June 30, 2011                                                        Page 1 of 1
                                                                                                                            Amounts in Dollars

                                                                     Billing    Pro Forma
                                           Class                     Entity      Number                                  Pro Forma Description                                    Supporting Witness   Pro Forma
                     UTILITY & EXECUTIVE MANAGEMENT                ESI         AJ16           Remove MISO Costs                                                      Considine, Michael P                (216,324)
                     UTILITY & EXECUTIVE MANAGEMENT                ESI         AJ21-01        Remove Company Aircraft Costs                                          Barrilleaux, Chris                     (1,589)
                     UTILITY & EXECUTIVE MANAGEMENT                ESI         AJ21-03        Remove Rate Case Support Costs                                         Considine, Michael P                     (148)
                     UTILITY & EXECUTIVE MANAGEMENT                ESI         AJ21-05        Remove Ticket Costs                                                    Barrilleaux, Chris                    (20,554)
                     UTILITY & EXECUTIVE MANAGEMENT                ESI         AJ21-07        Remove Non-Recoverable Costs                                           Barrilleaux, Chris                    (13,637)
                     UTILITY & EXECUTIVE MANAGEMENT                ESI         AJ21-08        Remove costs from the Gas Operations organization.                     Barrilleaux, Chris                     (1,281)
                     UTILITY & EXECUTIVE MANAGEMENT                ESI         AJ21-11        Correct Capital Projects                                               Tumminello, Stephanie B                     1
                     UTILITY & EXECUTIVE MANAGEMENT                ESI         AJ22           Affiliate Portion of Employee Changes and Wage Increases               Considine, Michael P                   21,631

                                                                   ESI                                                                                                                                   (231,900)

                     UTILITY & EXECUTIVE MANAGEMENT                Total                                                                                                                                 (231,900)

                     Total                                                                                                                                                                               (231,900)
3-65




                             Amounts may not add or tie to other schedules due to rounding.                                                                                                                  EXHIBIT JFD-D
                                                                                                                            Domino, Joe                                                                         Page 1 of 1
    This page has been intentionally left blank.




2011 ETI Rate Case                       3-66
                                              SOAH Docket No. XXX-XX-XXXX
                                                      PUC Docket No. 39896
                                                        ETI 2011 Rate Case
                                                        ETI EXHIBIT NO. 34
                                     DOCKET NO. 39896


              APPLICATION OF ENTERGY           §    PUBLIC UTILITY COMMISSION
              TEXAS, INC. FOR AUTHORITY        §
              TO CHANGE RATES AND              §           OF TEXAS
              RECONCILE FUEL COSTS             §




                                    DIRECT TESTIMONY


                                              OF


                                    ROBERT R. COOPER


                                          ON BEHALF OF


                                   ENTERGY TEXAS, INC.




                                      NOVEMBER 2011




2011 ETI Rate Case                                              8-1
                                       ENTERGY TEXAS, INC.
                              DIRECT TESTIMONY OF ROBERT R. COOPER
                                          2011 RATE CASE

                                          TABLE OF CONTENTS

                                                                                      Page

              I.     Introduction and Purpose                                           1

              II.    The Entergy System Planning Principles and Objectives              4

              III.   Resources Acquired through Planning Analysis Processes in this
                     Reconciliation Period                                              11

                     A.    Resources Acquired Through an RFP Process                    12

                     B.    Resources Acquired Through Bilateral Negotiations            16

              IV.    Determination of Allocation for Power Purchases                    18




                                                EXHIBITS

              Exhibit RRC-1       PPR Capacity Costs (Highly Sensitive)




2011 ETI Rate Case                                                           8-2
              Entergy Texas, Inc                                                      Page 1 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case


        1                           I.      INTRODUCTION AND PURPOSE

        2     Q.     PLEASE STATE YOUR NAME AND CURRENT BUSINESS ADDRESS.

        3     A.     My name is Robert R. Cooper. My business address is Parkwood II Bldg.,

        4            Suite 300, 10055 Grogans Mill Road, The Woodlands, Texas 77380.

        5

        6     Q.     BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY?

        7     A.     I am employed by Entergy Services, Inc. (“ESI”), the service company for

        8            the Entergy Operating Companies (“Operating Companies”), as Manager,

        9            Generation Planning & Models. In that capacity, among other activities, I

       10            provide resource planning services to the Operating Companies, which

       11            include Entergy Texas, Inc. (“ETI” or “the Company”), Entergy Gulf States

       12            Louisiana, L.L.C. (“EGSL”), Entergy Arkansas, Inc. (“EAI”), Entergy

       13            Louisiana, LLC (“ELL”), Entergy Mississippi, Inc. (“EMI”), and Entergy New

       14            Orleans, Inc. (“ENOI”). These six Operating Companies, along with ESI,

       15            acting as agent, are collectively referred to as the “System.” I work in the

       16            System Planning and Operations (“SPO”) department, which is an

       17            organization within ESI.

       18

       19     Q.     PLEASE DESCRIBE YOUR CURRENT JOB RESPONSIBILITIES.

       20     A.     My current job responsibilities include long-term supply-side resource

       21            planning for the Operating Companies, including ETI. In this function, I

       22            direct a staff that performs engineering and economic analyses of the




2011 ETI Rate Case                                                             8-3
              Entergy Texas, Inc                                                      Page 2 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case


        1            power and fuel supply requirements of the System in order to provide a

        2            reliable and economical resource portfolio.

        3

        4     Q.     PLEASE         DESCRIBE         YOUR   EDUCATION       AND      BUSINESS

        5            EXPERIENCE.

        6     A.     I have a Masters Degree in Business Administration from the University of

        7            New Orleans and a Bachelor of Science Degree in Engineering from

        8            Southern Illinois University.     After receiving my Bachelor’s degree, I

        9            worked for four years with Illinois Power Company in Decatur, Illinois, as a

       10            Planning Engineer in the Load Management Research Department.               I

       11            began working for Entergy in 1984 as a Research Analyst in the

       12            Forecasting department of Middle South Services, Inc., where I performed

       13            economic analyses of end-use energy consumption. I have worked for

       14            Entergy Services, Inc., or its predecessors, in various planning capacities

       15            over the last 27 years. In the ensuing years, I progressed into positions of

       16            increasing responsibility in roles that involved engineering, economic and

       17            market analysis.        In 1996, I was promoted to Segment Manager

       18            responsible for the development, implementation and measurement of

       19            demand-side programs for small business markets. In July of 1999, I took

       20            the position as Manager of Generation Planning in the Energy

       21            Management Organization.          In February of 2004, that position was

       22            expanded to include responsibility for the activities, staff and planning

       23            models of production cost analysis.




2011 ETI Rate Case                                                             8-4
              Entergy Texas, Inc                                                                   Page 3 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case


        1     Q.        ON WHOSE BEHALF ARE YOU FILING THIS DIRECT TESTIMONY?

        2     A.        I am filing this Direct Testimony on behalf of ETI.

        3

        4     Q.        WHAT IS THE PURPOSE OF YOUR TESTIMONY?

        5     A.        My testimony provides the following:

        6               •       A description of the planning principles and objectives utilized by

        7                       the System in determining the resources that were necessary to

        8                       meet its load requirements, and how the selected products fulfill

        9                       those objectives;

       10               •       A discussion of the types of resources that were acquired in

       11                       furtherance of the System’s planning principles to meet the

       12                       System’s incremental resource needs since the Company’s last

       13                       base rate case. 1       As a part of this discussion, I describe the

       14                       evaluation process that was conducted for the formal Requests for

       15                       Proposals (“RFPs”) that were issued for the System during the

       16                       Reconciliation Period. I also identify resources acquired through

       17                       bilateral negotiations resulting from unsolicited offers;

       18               •       A discussion of the allocation among the Operating Companies of

       19                       the purchased power resources included in this reconciliation filing;

       20               •       The identification and quantification of capacity costs the Company

       21                       requests be recovered through a Purchased Power Recovery

              1
                     In the Company’s last base rate case, Docket No. 37744, I discussed resources that became
                     effective during the rate year for that case (July 2009 through June 2010), which period is
                     included in the current fuel reconciliation period.




2011 ETI Rate Case                                                                          8-5
              Entergy Texas, Inc                                                          Page 4 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case


        1                       Rider. As part of this discussion, I discuss new contracts beginning

        2                       after the Test Year and effective during the Rate Year.

        3

        4                 II.       THE ENTERGY SYSTEM PLANNING PRINCIPLES
        5                                    AND OBJECTIVES

        6     Q.     WILL YOU PLEASE PROVIDE A SUMMARY OF THE ENTERGY

        7            SYSTEM’S PLANNING PRINCIPLES AND OBJECTIVES?

        8     A.     The System’s planning principles, planning objectives, and resource

        9            supply strategies are applied by the Operating Committee with the intent

       10            to produce a portfolio of resources to match the needs of the customers of

       11            the Operating Companies. They include the following six basic resource

       12            supply objectives:

       13            •          Reliability – Provide adequate resources to meet customer peak

       14                       demands with adequate reliability.

       15            •          Production Cost – Baseload Supply Requirements – Provide low-

       16                       cost baseload resources to serve baseload requirements (the load

       17                       level that is expected to be exceeded for at least 85% of all hours of

       18                       the year).

       19            •          Production Cost – Load-following Supply Requirements – Provide

       20                       efficient, dispatchable load-following resources to serve the time-

       21                       varying load shape levels that are above the baseload requirement

       22                       load levels.




2011 ETI Rate Case                                                                  8-6
              Entergy Texas, Inc                                                          Page 5 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case


        1            •       Generation Portfolio Enhancement – Improve the efficiency of the

        2                    generation portfolio and avoid an over-reliance on aging resources.

        3            •       Risk Mitigation – Price Stability – Mitigate the effects on production

        4                    costs of price volatility associated with uncertainties in fuel and

        5                    purchased power costs.

        6            •       Risk Mitigation – Supply Diversity – Mitigate the effects on

        7                    production costs of major supply disruptions that could occur from

        8                    concentrated or systematic risks, for example outages of a single

        9                    generation facility.

       10

       11     Q.     WILL YOU PLEASE DESCRIBE THE BACKGROUND FOR THE

       12            ENTERGY SYSTEM’S RESOURCE SUPPLY STRATEGY?

       13     A.     The generation and bulk transmission facilities of the Operating

       14            Companies are planned and operated as a single, integrated electric

       15            system,     pursuant     to     the   Entergy   System   Agreement    (“System

       16            Agreement”), which has been approved by the Federal Energy Regulatory

       17            Commission (“FERC”).            When planning for the System, the Operating

       18            Committee is guided by the System’s current planning principles, planning

       19            objectives, and resource supply strategies for short- and long-term

       20            planning. The System Agreement charges the Operating Committee with

       21            the responsibility for, among other things, determining generation addition

       22            or acquisition plans that provide capacity to meet System load projections

       23            and reliable service to customers at a reasonable cost consistent with




2011 ETI Rate Case                                                                8-7
              Entergy Texas, Inc                                                      Page 6 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case


        1            sound business practice and operational constraints. Consistent with the

        2            System Agreement, the resource supply plans that serve as the basis for

        3            acquisition of the resources must necessarily address the System needs

        4            as a whole.

        5                    The current planning objectives and principles were approved

        6            initially by the Operating Committee in June 2002 and subsequently

        7            refined and adopted in January 2003 as the Strategic Supply Resource

        8            Plan.      Guided by these principles and objectives, the Operating

        9            Committee periodically approves updates to the resource plan developed

       10            by the SPO organization which address the current and future needs of

       11            the Operating Companies’ retail customers.        Beginning in 2009, the

       12            Strategic Supply Resource Plan was renamed the Strategic Resource

       13            Plan (“SRP”) in order to more accurately reflect the full scope of the

       14            planning effort; however, the basic set of principles and objectives that

       15            guide long-term portfolio design remains unchanged.

       16

       17     Q.     WILL YOU PLEASE EXPLAIN HOW THE SRP GUIDES THE TYPES OF

       18            PURCHASES MADE BY SPO?

       19     A.     The SRP is a set of principles and processes that gives SPO guidance on

       20            the mix of owned generation and different types of power purchases that

       21            best meet customers’ needs for reliable service at a reasonable cost. The

       22            SRP includes three major planning horizons: strategic (20-year horizon),

       23            tactical (3-year horizon), and annual (1-year horizon). First, my group, the




2011 ETI Rate Case                                                             8-8
              Entergy Texas, Inc                                                        Page 7 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case


        1            SPO Planning Analysis Group, periodically assesses the capability of the

        2            generating resources available to the System. This group also develops a

        3            load forecast, which is updated periodically or when significant changes

        4            occur to the System. A comparison of the load forecast and the resource

        5            capability is used to identify the needs of the System and guide the

        6            planning processes for obtaining additional resources. As provided in the

        7            SRP, the additional resource needs are initially met through the strategic

        8            planning process with the solicitation of proposals for long-term resources.

        9            The results of the strategic planning process influence the quantity and

       10            type of resources solicited in the next phase, the tactical planning process.

       11            The tactical planning process solicits proposals for “limited-term” products

       12            that meet the criteria set to satisfy the System’s needs for this horizon.

       13            After these limited-term products have been secured, the remainder of the

       14            System’s needs is met through the annual planning process, with short-

       15            term power purchases of one year or less. The use of these different

       16            planning processes is designed to result in a diversified portfolio of reliable

       17            resources at a reasonable cost.

       18

       19     Q.     WHY DOES THE SYSTEM NEED A MIX OF GENERATION TYPES?

       20     A.     The planning process seeks to provide a portfolio of resources that, in

       21            total, achieve the planning objectives in a balanced and cost effective

       22            manner.        Because the cost and performance characteristics of

       23            technologies differ, no single technology or generation type economically




2011 ETI Rate Case                                                                8-9
              Entergy Texas, Inc                                                         Page 8 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case


        1            meets the diverse planning objectives of the SRP. For example, baseload

        2            resources typically cost more to construct on a per-megawatt (“MW”) basis

        3            than peaking resources but operate with relatively low variable cost.

        4            Despite its relatively high construction cost, a base load resource can be

        5            the most economic alternative to serve the base load supply role, because

        6            the resource is expected to operate in most hours at high utilization levels

        7            due to its relatively lower fuel cost. Consequently, the capital cost of a

        8            base load resource is spread over many megawatt hours (“MWh”) of

        9            output, resulting in a relatively low total production cost on a $/MWh basis.

       10            Conversely, a peaking unit is expected to operate at low capacity

       11            utilization levels. As such, the most economic alternatives for peaking and

       12            reserve capacity would be units with a relatively low capital cost, even if

       13            their variable costs were higher. In both cases, the unique cost structure

       14            of a resource allows it to be the lowest reasonable cost alternative for the

       15            particular supply role that the unit will fulfill. This is why the SRP seeks to

       16            match generation supply to customer load shape requirements.

       17

       18     Q.     HOW DOES THE SYSTEM DETERMINE THE CAPABILITY OF ITS

       19            GENERATION RESOURCES FOR THE SRP PLANNING PROCESSES?

       20     A.     The System uses seasonal ratings for its generating units to reflect the

       21            fact that the output of units may vary depending on the season of the year

       22            and the condition of the generating unit. In the heat of the summer, the

       23            output of a unit on the System may not be equal to the Maximum




2011 ETI Rate Case                                                                8-10
              Entergy Texas, Inc                                                      Page 9 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case


        1            Demonstrated Capability of that unit.     The seasonal capability of the

        2            System’s units is reassessed semi-annually.       In addition to resources

        3            owned by the Operating Companies, the System includes in its planning

        4            assumptions any commitments for resources resulting from wholesale

        5            transactions that commenced prior to the applicable SRP planning

        6            process.     This includes, for example, East Texas Electric Cooperative

        7            Inc.’s (“ETEC”) approximately 230 MW of generating resources that ETI

        8            obtains as part of the partial requirements agreement between ETEC and

        9            ETI.

       10

       11     Q.     PLEASE DESCRIBE THE PROCESS THAT THE SYSTEM USES TO

       12            DEVELOP THE LOAD FORECAST FOR THE SRP PLANNING

       13            PROCESSES.

       14     A.     The load forecasting process used by the System is designed to forecast

       15            hourly data for each study year, jurisdiction, and customer class. Metrix

       16            LT is used to prepare the load forecast, using numerous sources of input

       17            data. The sources of input data that are used in the Metrix LT model

       18            include an energy sales forecast, historical weather data, historical load

       19            shape data, historical curtailment information for curtailable/interruptible

       20            customers, and transmission loss estimates.        The load forecast also




2011 ETI Rate Case                                                             8-11
              Entergy Texas, Inc                                                                  Page 10 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case


        1               includes a projection of the amount of load that is expected to be served

        2               under full or partial requirements wholesale customers, such as ETEC. 2

        3

        4     Q.        WHAT IS THE NET EFFECT THAT ETEC LOAD PLACES ON ETI’S

        5               SYSTEM NEED AT THE SAME TIME ETEC PROVIDES RESOURCES

        6               TO ETI?

        7     A.        ETEC’s partial requirements load is netted against the ETEC resources

        8               credited to ETI and placed under the control of the Entergy System

        9               Operator. ETEC’s incremental partial requirements demand is projected

       10               to be less than the 150 MW minimum billing demand under the partial

       11               requirements contract, which is further discussed by Company witness

       12               Phillip May.

       13

       14     Q.        BASED ON THE ASSESSMENT OF LOAD REQUIREMENTS AND

       15               GENERATING           CAPABILITY,       WHAT       IS   THE     COMPANY’S          NET

       16               RESOURCE NEED?

       17     A.        In addition to owned resources as well as resources currently under

       18               contract and the resources I discuss in my testimony, ETI projects an

       19               incremental need of 260 MW in 2012 and 504 MW in 2013.




              2
                     ETEC’s partial requirements contract with ETI provides for a minimum billing demand of 150
                     MW.




2011 ETI Rate Case                                                                         8-12
              Entergy Texas, Inc                                                      Page 11 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case


        1            III.   RESOURCES ACQUIRED THROUGH PLANNING ANALYSIS
        2                    PROCESSES IN THIS RECONCILIATION PERIOD

        3     Q.      HOW IS THIS SECTION OF YOUR TESTIMONY ORGANIZED?

        4     A.      The System generally acquires the resources necessary to satisfy the

        5             forecasted load requirements of the System either through some type of

        6             RFP process to solicit competitive bids for resources or bi-lateral

        7             negotiations when the System receives unsolicited offers. Accordingly, I

        8             have divided the resources discussed in this section into those acquired

        9             through an RFP process and those acquired through bilateral negotiations

       10             following an unsolicited offer.

       11

       12     Q.      WOULD       SPO     ACQUIRE       A   RESOURCE    THOUGH        BILATERAL

       13             NEGOTIATIONS RATHER THAN AN RFP PROCESS?

       14     A.      Yes. As a practical matter, SPO cannot control whether an interested

       15             party makes an unsolicited offer outside the context of an RFP or the

       16             timing of such an offer. It is appropriate that such offers be evaluated in

       17             the context of the needs of the System. SPO generally employs the same

       18             criteria as that used in an RFP to determine the need for the resource and

       19             the reasonableness of the price.




2011 ETI Rate Case                                                             8-13
              Entergy Texas, Inc                                                       Page 12 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case


        1     Q.     OTHER THAN YOUR TESTIMONY, DOES THE COMPANY’S FILING

        2            INCLUDE       OTHER       SUPPORT   FOR     THE    TRANSACTIONS          YOU

        3            DISCUSS IN YOUR TESTIMONY?

        4     A.     Yes.    The workpapers to Schedule I-15 includes portions of Entergy

        5            Operating Committee minutes and attachments that support the resources

        6            discussed and the allocation of those resources among the Operating

        7            Companies. My workpapers, discussed below, also provide support for

        8            the selection of these resources.

        9

       10                     A.     Resources Acquired Through an RFP Process

       11     Q.     PLEASE PROVIDE AN OVERVIEW OF THE ACQUISITION OF

       12            RESOURCES THROUGH THE RFP PROCESS.

       13     A.     The formal RFP process begins with the identification of the resource

       14            needs for the System, as I discussed above, which results in the

       15            determination of which products the RFP will request. SPO then oversees

       16            the design, development, and implementation of the RFP.            As further

       17            described below, an Independent Monitor is typically involved with this

       18            process.      The objectives, products sought, process and other details

       19            unique to each RFP are reduced to writing and publicly posted on ESI’s

       20            RFP website, and interested parties are notified of the posting. I include in

       21            my workpapers the Main Body of the RFP conducted during the

       22            Reconciliation Period and discussed in my testimony.




2011 ETI Rate Case                                                              8-14
              Entergy Texas, Inc                                                     Page 13 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case


        1                    Once the proposals have been received, the Planning Analysis

        2            group evaluates the proposals under strict confidentiality protocols, and

        3            recommends to the Operating Committee which proposals should be

        4            placed on the short list for further negotiation.     After the Operating

        5            Committee approves the proposals to be included on the short list, SPO’s

        6            Supply Procurement group manages the negotiations with the short-listed

        7            bidders.     The resource planning principles, planning objectives, and

        8            resource supply strategies that the Operating Committee adopted to guide

        9            the overall planning process were described in detail in each formal RFP

       10            issued by ESI on behalf of the Operating Companies.

       11

       12     Q.     WHAT IS THE ROLE OF AN INDEPENDENT MONITOR (IM) IN THE

       13            RFP PROCESS?

       14     A.     ESI’s RFP process typically involves the retention of an IM to ensure that

       15            the RFP is conducted in a fair and impartial manner. The IM (1) oversees

       16            the design and implementation of the RFP solicitation, evaluation,

       17            selection, and contract negotiations process to ensure that it will be

       18            impartial and objective, and (2) provides an objective, third-party

       19            perspective concerning ESI’s efforts to ensure that all proposals are

       20            treated in a consistent fashion and that no undue preference is provided to

       21            any Bidder. The IM’s responsibilities for each RFP are set out in a Scope

       22            of Work made available on the Company’s RFP website. The Main Body

       23            of the RFP discussed in my testimony and the IM report corresponding to




2011 ETI Rate Case                                                            8-15
              Entergy Texas, Inc                                                            Page 14 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case


        1               that RFP is made part of my workpapers. Although I have attached these

        2               IM reports as workpapers, it is important to note that the content of that

        3               report is solely the work of the IM, who is entirely independent of the

        4               Company and not a consultant to the Company.

        5

        6     Q.        IN GENERAL, HOW ARE RFP PROPOSALS EVALUATED?

        7     A.        For the RFP, the evaluation process considers the effect of each of the

        8               proposals on the overall expected production costs of the System. The

        9               evaluation of life-of-unit (“LOU”) and day-ahead MUCCO and MUCPA

       10               proposals include production cost simulations to account for the fact that

       11               each of the resources has different characteristics, such as cost,

       12               availability, and duration. 3    The objective of the production costing

       13               evaluation process is to identify the resources that produced the lowest

       14               reasonable     total   System   production    cost   for   each     incremental

       15               kilowatt added.

       16                      Qualitative evaluations of various non-economic factors are also

       17               performed.      As the field of viable candidates narrowed, further

       18               negotiations with bidders are held to secure the most favorable

       19               terms possible.




              3
                     A MUCCO is a Multi-year Unit-Contingent Call Option. A MUCPA is a Multi-year Unit-
                     Contingent Purchase Agreement for a generating resource.




2011 ETI Rate Case                                                                   8-16
              Entergy Texas, Inc                                                            Page 15 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case


        1                    Generally, the evaluation of day-ahead MUCCO and dispatchable

        2            MUCPA products, the two most prevalent RFP products requested, use a

        3            process that included the following three major steps:

        4                    1.      initial individual proposal screening and production cost

        5                            analysis which result in individual candidate proposal

        6                            selection, and individual candidate proposal deliverability

        7                            evaluation;

        8                    2.      verification of individual candidate proposals considering

        9                            deliverability evaluation; and

       10                    3.      portfolio identification, portfolio production cost analysis,

       11                            portfolio deliverability evaluation, and portfolio selection.

       12

       13     Q.     WHAT ROLE DOES THE OPERATING COMMITTEE SERVE IN THE

       14            DETERMINATION OF WHICH RFP OFFERS ARE ACCEPTED?

       15     A.     As Company witness Patrick J. Cicio testifies, the Operating Committee

       16            has been delegated the authority through the System Agreement to

       17            determine which resources should be acquired for the System to meet its

       18            load obligations and serve its customers at a reasonable cost. As such,

       19            the Operating Committee determines which RFP offers are accepted once

       20            they have been evaluated through the RFP process.




2011 ETI Rate Case                                                                   8-17
              Entergy Texas, Inc                                                       Page 16 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case


        1     Q.     DID ESI CONDUCT AN RFP DURING THE RECONCILIATION PERIOD

        2            OR TEST YEAR THAT RESULTED IN THE ACQUISITION OR

        3            PROCUREMENT OF RESOURCES OR CONTRACTS THAT WERE

        4            ALLOCATED TO ETI?

        5     A.     Yes. During 2009 and 2010, ESI conducted the Summer 2009 Request

        6            for Proposals for Long-Term Supply-Side Resources (“Summer 2009

        7            RFP”), seeking combined-cycle gas turbine (“CCGT”), combustion turbine

        8            (“CT”), and solid fuel resources. The Summer 2009 RFP resulted in a ten-

        9            year power purchase agreement (“PPA”) between Calpine Energy

       10            Services, L.P. (“Calpine”) and ETI for the purchase of 485 megawatts

       11            (“MW”) of capacity and energy from Calpine’s Carville Energy Center in

       12            St. Gabriel, Louisiana (the “Carville Contract”). Purchases pursuant to the

       13            Carville Contract will begin during the Rate Year, on June 1, 2012, and will

       14            be discussed in Section V of my testimony.

       15

       16                  B.      Resources Acquired Through Bilateral Negotiations

       17     Q.     WHAT RESOURCES WERE ACQUIRED THROUGH BI-LATERAL

       18            NEGOTIATIONS OUTSIDE OF A FORMAL RFP PROCESS?

       19     A.     The following resources were acquired through bi-lateral negotiations in

       20            the Reconciliation Period and Test Year:

       21            •       a 75 MW one-year call option between ETI and NRG for capacity

       22                    and energy from the Exxon facility in Beaumont, Texas, with a

       23                    delivery period that began on March 1, 2011; and




2011 ETI Rate Case                                                              8-18
              Entergy Texas, Inc                                                         Page 17 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case


        1            •        a 100 MW MUCCO between ETI and Dow Pipeline for capacity and

        2                     energy from the Dow Pipeline facility in Iberville Parish, Louisiana

        3                     with a three-year delivery term that began in April 1, 2011.

        4            In addition, as discussed later in my testimony, ETI contracted with Sam

        5            Rayburn Municipal Power Agency ("SRMPA") for 225 MW of SRMPA

        6            system resources for a delivery term of twenty-five years. Deliveries are

        7            scheduled to begin on December 1, 2011.

        8

        9     Q.     PLEASE DISCUSS GENERALLY THE DECISIONS TO ENTER INTO

       10            THESE BILATERAL PURCHASES.

       11     A.     The 75 MW purchase from NRG resulted from SPO’s ongoing

       12            communications with generators in the ETI service area regarding

       13            opportunities to address ETI’s continuing need for capacity. The 100 MW

       14            purchase from Dow Pipeline was an extension of a then-existing contract

       15            for the same level of capacity that first began on January 1, 2008. The 225

       16            MW purchase from SRMPA will provide benefits to ETI as a source of

       17            much-needed long-term base load capacity at an economically attractive

       18            price.




2011 ETI Rate Case                                                                8-19
              Entergy Texas, Inc                                                                  Page 18 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case


        1            IV.       DETERMINATION OF ALLOCATION FOR POWER PURCHASES

        2     Q.           HOW DOES THE ENTERGY SYSTEM DETERMINE THE ALLOCATION

        3                  OF NEW RESOURCES AMONG THE OPERATING COMPANIES?

        4     A.           As discussed in Company witness Cicio’s Direct Testimony, the System

        5                  Agreement (Section 4.02) allows the Operating Committee to allocate

        6                  certain power purchases on a System-wide basis to all the Operating

        7                  Companies by their responsibility ratios, or to directly assign a purchase to

        8                  less than all of the Operating Companies, and do so on a basis other than

        9                  responsibility ratio. The following factors have been considered by the

       10                  Operating Committee in recent resource allocation decisions:

       11                  •     Relative Total Production Costs – Long-term total production cost

       12                        trends among the Operating Companies.

       13                  •     Peak Load + 10% Capacity Deficit – Each Operating Company’s

       14                        resource capability position relative to its peak load plus a minimum

       15                        reserve level of 10%.

       16                  •     Supply Role Capacity Deficit – Each Operating Company’s

       17                        resource position with regard to its capacity requirements by supply

       18                        role.

       19                  •     Responsibility Ratio – Each Operating Company’s resource

       20                        position relative to its responsibility ratio.

       21                  •     Supply Risks – Each Operating Company’s supply risks associated

       22                        with generation unit availability and price volatility.




2011 ETI Rate Case                                                                         8-20
                 Entergy Texas, Inc                                                            Page 19 of 25
                 Direct Testimony of Robert R. Cooper                               Revised - Errata No. 2
                 2011 Rate Case
,,
     \

           1     Q.      WHAT IS ETl'S ALLOCATION OF THE CONTRACTS YOU IDENTIFY

           2             ABOVE?

           3     A       The contracts were allocated by the Operating Committee to ETI as

           4             follows:

           5             •      the 485 MW Carville Contract was allocated 50% to ETI and 50% to

           6                    EGSL, pursuant to ETl's sale of 50% of the associated capacity

           7                    and energy to EGSL under Service Schedule MSS-4 of the Entergy

           8                    System Agreement; 4

           9             •      the 75 MW purchase from NRG was allocated 100% to ETI;

          10             •      the 100 MW purchase from Dow Pipeline was allocated 50% to

          11                    ETI; and

          12             •      the 225 MW purchase from SRMPA was allocated 100% to ETI.

          13                    As discussed previously, the allocation decisions associated with

          14             these transactions are recorded in Minutes from the Entergy Operating

          15             Committee meetings, which minutes and attachment are included in the

          16             workpapers to Schedule 1-15 of the filing.

          17

          18                        "       PUROi IASED POWER RECOVERY RIDER __.fl_.

          19     Q.      WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY?

          20     A       Af:. elesc1 ibed ii 1 ti 1e testil 11011y ef Philli13 R. May, the Gem pa Ry is

          21             ~es-ting       tnat all purchased capacity costs, i11cludi11g Se1vice Schedule

                 4
                      Company witness Cicio describes the Entergy System Agreement and its associated
                      schedules.



         2011 ET! Rate Case                                                             8-21
                                                           5
              Entergy Texas, Inc                                                          Page 20 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case                                                                              i




        2            through a Purchased Power Recovery Rider ("PPR"). T · section of my

        3            testimony addresses the following:

        4            •       I provide an adjusted              Year level of purchased capacity

        5                                                  Company requests authority to recover

        6

        7            •       My update of the Test Year purchased capacity costs includes a

        8                    description of new purchased           power contracts that become

        9                    effective after the Test Year and will be effective during the Rate

       10                    Year.

       11            As explained by Company witness May, if the PPR is not approved by the

       12            Commission, the Company requests that the adjusted Test Year amounts

       13            be included for recovery in base rates.

       14

       15     Q.     WHAT ARE THE ADJUSTED TEST YEAR PURCHASED CAPACITY

       16            COSTS TO BE RECOVERED IN THE PPR?

       17     A.     The total adjusted Test Year purchased capacity costs for the Company is

       18            roughly $276 million. This level of expense represents Test Year costs

       19            adjusted for known and measurable changes that will occur in the Rate

       20            Year. Highly Sensitive Exhibit RRC-1, attached hereto, provides a break

       21            down of this amount.            The exhibit separates capacity costs into four

       22            categories:     (1) third-party contracts, (2) legacy affiliate contracts (or

       23            Service Schedule MSS-4 agreements), (3) other affiliate contracts, and (4)




2011 ET! Rate Case                                                                 8-22
              Entergy Texas, Inc                                                         Page 21 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case


        1            Service Schedule MSS-1 costs.          The term “legacy affiliate contracts”

        2            refers to those affiliate contracts resulting from the December 31, 2007

        3            jurisdictional separation of Entergy Gulf States, Inc. (“EGSI”) into ETI and

        4            EGSL, pursuant to which ETI purchases its allocated share of natural gas

        5            power plants located in Louisiana and owned by EGSL as a result of the

        6            separation. “Other affiliate contracts” refers to all other affiliate contracts

        7            whereby ETI purchases capacity and associated energy from another

        8            Entergy Operating Company.

        9

       10     Q.     PLEASE DISCUSS THE NEW THIRD-PARTY CONTRACTS THAT

       11            WERE NOT IN PLACE DURING THE TEST YEAR, BUT WILL BE IN

       12            PLACE DURING THE RATE YEAR.

       13     A.     The following new third-party contracts are included in this category:

       14            •       The 485 MW Carville Contract—As discussed previously, this ten-

       15                    year PPA resulted from the Summer 2009 RFP and is allocated

       16                    50% to ETI. Purchases under the Carville Contract will begin on

       17                    June 1, 2012. ETI participates in the Carville Contract as the only

       18                    counterparty to Calpine for the full level of capacity and associated

       19                    energy supplied under the contract. ETI then sells EGSL 50% of

       20                    the capacity and energy for the full term of the contract in return for

       21                    EGSL paying ETI half of all costs under the contract, pursuant to

       22                    Service Schedule MSS-4 of the Entergy System Agreement. ETI

       23                    (along with EGSL) previously received capacity and energy from




2011 ETI Rate Case                                                                8-23
              Entergy Texas, Inc                                                               Page 22 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case


        1                       the Carville Energy Center pursuant to a one-year contract from

        2                       June 1, 2008 through May 31, 2009.

        3               •       A twenty-five year PPA between SRMPA and ETI for 225 MW of

        4                       capacity and associated energy. Deliveries under the SRMPA PPA

        5                       are scheduled to begin on December 1, 2011. SRMPA is a joint

        6                       powers agency composed of the municipalities of Liberty,

        7                       Livingston and Jasper, Texas and the City of Vinton, Louisiana. In

        8                       a recent filing at FERC, SRMPA indicated that it restructured its

        9                       long-term supply portfolio (some of which is obtained from affiliates

       10                       of ETI) so that it could reduce its annual debt service obligations,

       11                       which restructuring left SRMPA with additional resources that it

       12                       offered to ETI. 5 The SRMPA PPA will be a “system contingent”

       13                       transaction, meaning SRMPA is required to deliver energy from its

       14                       system resources to the extent its resources are available.

       15

       16     Q.        WHAT ARE THE SERVICE SCHEDULE MSS-1 COSTS INCLUDED IN

       17               THE EXHIBIT RRC-1?

       18     A.        As described by Company witness Cicio, ETI’s MSS-1 (Reserve

       19               Equalization) costs are a function of the level of resources owned or

       20               controlled by ETI relative to its share of System load. The MSS-1 costs

       21               included in Highly Sensitive Exhibit RRC-1 reflect the known and


              5
                     Entergy Services, Inc., Docket No. ER11-4415. See also EWO Marketing, Inc., Docket No.
                     ER11-4410.




2011 ETI Rate Case                                                                      8-24
              Entergy Texas, Inc                                                      Page 23 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case


        1            measurable changes to ETI’s resources as discussed above relative to

        2            ETI’s projected share of System load for the same time period.

        3

        4     Q.     DO THE PPAS YOU HAVE DISCUSSED ABOVE HELP SATISFY

        5            IDENTIFIED RELIABILITY NEEDS OF THE SYSTEM, INCLUDING ETI?

        6     A.     Yes, for the reasons discussed above and as further set out in the

        7            presentations to the Operating Committee contained in the workpapers to

        8            Schedule I-15.

        9

       10     Q.     DOES ETI EXPECT TO PLACE A SIGNIFICANT RELIANCE ON

       11            PURCHASED POWER RESOURCES BEYOND THE RATE YEAR?

       12     A.     Yes.    My Exhibit RRC-1 demonstrates that ETI’s current resource mix

       13            places a significant reliance on purchased power, more than doubling the

       14            amount of third-party capacity purchases reflected in the rate year for

       15            ETI’s last rate case (rate year of July 2010 – June 2011), for an increase

       16            of more than $36 million. I expect that consideration of and reliance on

       17            third-party purchases will continue.

       18

       19     Q.     DO THE COMPANY'S RECENT RESOURCE COMMITMENTS TAKE

       20            INTO CONSIDERATION ENVIRONMENTAL INTEGRITY?

       21     A.     Yes. For example, two recent long-term transactions resulting from RFPs

       22            include express terms requiring the seller's compliance with all applicable




2011 ETI Rate Case                                                            8-25
              Entergy Texas, Inc                                                       Page 24 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case


        1            environmental laws, including compliance with changes in environmental

        2            laws and regulations.

        3

        4     Q.     ARE THE PPAS EXPECTED TO IMPROVE SERVICE OR LOWER

        5            COSTS TO CUSTOMERS?

        6     A.     Yes. As discussed above, the purchases are intended to help meet the

        7            Company’s (and the System's) reliability needs, including those of ETI, at

        8            a cost lower than other alternatives. RFPs and negotiations conducted on

        9            behalf of the Company and the other Entergy Operating Companies are

       10            designed specifically to realize that objective.    As a typical Entergy

       11            Operating Company RFP puts it: a primary objective of the RFP is “to

       12            solicit competitive proposals to…meet customer’s needs in a reliable and

       13            economical manner.”         The evaluation process is designed “to…select

       14            proposals that meet ESI’s resource planning and risk management

       15            objectives at the lowest reasonable cost.” The primary objective of the

       16            economic evaluation is to “procure resources that balance the System’s

       17            objectives, including reliability, lowest reasonable cost.”      This process

       18            includes a net System Benefits analysis that “relies on production cost

       19            modeling to assess the effects of each proposal, or combination

       20            of…proposals on total System cost.”        Based on this production cost

       21            analysis, a portion of the energy from the resources described above is

       22            expected to displace energy from higher cost system-owned generation.

       23            These objectives and analyses guided the procurement of the resources




2011 ETI Rate Case                                                             8-26
              Entergy Texas, Inc                                                        Page 25 of 25
              Direct Testimony of Robert R. Cooper
              2011 Rate Case


        1            described previously in my testimony—whether obtained through RFP

        2            solicitation and or bilateral (unsolicited) negotiations.

        3

        4     Q.     DOES THIS CONCLUDE YOUR TESTIMONY?

        5     A.     Yes.




2011 ETI Rate Case                                                               8-27
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2011 ETI Rate Case                               8-28
                                                                                   Exhibit RRC-1
                                                                              2011 TX Rate Case
                                                                                     Page 1 of 1
                                                                                 (Public Version)



              This exhibit contains information that is confidential and will be provided under

      the terms of the terms of the Protective Order (Confidentiality Disclosure Agreement)

      entered in this case.




2011 ETI Rate Case                                                            8-29
            This page has been intentionally left blank.




2011 ETI Rate Case                               8-30
                                     SOAH Docket No. XXX-XX-XXXX
                                             PUC Docket No. 39896
                                               ETI 2011 Rate Case
                                               ETI EXHIBIT NO. 39
                            DOCKET NO. 39896


     APPLICATION OF ENTERGY           §    PUBLIC UTILITY COMMISSION
     TEXAS, INC. FOR AUTHORITY        §
     TO CHANGE RATES AND              §           OF TEXAS
     RECONCILE FUEL COSTS             §




                           DIRECT TESTIMONY


                                     OF


                             PATRICK J. CICIO


                                 ON BEHALF OF


                          ENTERGY TEXAS, INC.




                             NOVEMBER 2011




2011 ETI Rate Case                                     9-1
                                 ENTERGY TEXAS, INC.
                         DIRECT TESTIMONY OF PATRICK J. CICIO
                                   2011 RATE CASE



                                   TABLE OF CONTENTS

                                                                                 Page

     I.      Introduction                                                           1 

     II.     costs associated with The Entergy System Agreement                     5 

             A.      Summary                                                        5 

             B.      The Entergy System Agreement                                   6 

             C.      Billing for Entergy System Agreement-Related Revenues and
                     Costs                                                         31 

     III.    The Energy and Fuel Management Class of Costs                         37 

             A.      The SPO Organization                                          39 

             B.      Overview of Costs – Energy and Fuel Management Class          43 

             C.      Necessity of Services                                         48 

             D.      Reasonableness of Energy and Fuel Management Charges          58 

             E.      Billing of Energy and Fuel Management Charges                 64 

             F.      Summary of SPO Capital Charges                                71 

     IV.     Conclusion                                                            75 




2011 ETI Rate Case                                                   9-2
                                      EXHIBITS

     Exhibit PJC-1   Entergy System Agreement

     Exhibit PJC-2   July 2008 Intra-System Bill

     Exhibit PJC-3   Families and Functions Chart

     Exhibit PJC-4   Functions and Classes Chart

     Exhibit PJC-5   SPO Organization Chart

     Exhibit PJC-6   Summary of SPO Capital Charges



     Exhibit PJC-A   Affiliate Billings by Witness, Class and Department

     Exhibit PJC-B   Affiliate Billings by Witness, Class and Project

     Exhibit PJC-C   Affiliate Billings by Witness, Class, Department and Project

     Exhibit PJC-D   Pro Forma Summary




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     Entergy Texas, Inc.                                                                   Page 1 of 75
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1                                       I.      INTRODUCTION

2    Q.       PLEASE STATE YOUR NAME AND CURRENT BUSINESS ADDRESS.

3    A.       My name is Patrick J. Cicio. My business address is Parkwood II Bldg.,

4             Suite 100, 10055 Grogan’s Mill Road, The Woodlands, Texas 77380.

5

6    Q.       ON WHOSE BEHALF ARE YOU PROVIDING THIS TESTIMONY?

7    A.       I am testifying on behalf of Entergy Texas, Inc. (“ETI” or the “Company”).

8

9    Q.       BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY?

10   A.       I am Director, Regulatory Affairs and Energy Settlements for the System

11            Planning and Operations (“SPO”) organization of Entergy Services, Inc.
                      1
12            (“ESI”),    the service company affiliate of the Entergy Operating

13            Companies, which coordinate, plan, and operate their electric generation

14            and bulk transmission facilities as a single, integrated electric system (the
                                                         2
15            “Entergy System” or the “System”).             As Director, Regulatory Affairs and

16            Energy Settlements, I am responsible for administering the Intra-System

17            Billing associated with the Entergy System Agreement, overseeing fuel


     1
          ESI is the services company affiliate of the Entergy Operating Companies that provides
          engineering, planning, accounting, technical, regulatory, and other administrative support
          services to each of the Entergy Operating Companies.
     2
          In addition to ETI, the Entergy Operating Companies are Entergy Arkansas, Inc. (“EAI”);
          Entergy Mississippi, Inc. (“EMI”); Entergy New Orleans, Inc. (“ENO”); Entergy Gulf States
          Louisiana, L.L.C. (“EGSL”); and Entergy Louisiana, LLC (“ELL”). On December 19, 2005, EAI
          gave notice that it will terminate its participation in the System Agreement effective December
          18, 2013. Entergy Mississippi provided similar notice to the Operating Companies on
          November 8, 2007 that it would terminate its participation effective November 7, 2015.




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     Entergy Texas, Inc.                                                          Page 2 of 75
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1            and power settlements and reporting, as well as compliance with the

2            electric reliability standards, directing the department budgets, and giving

3            guidance to the Regulatory Affairs Group which coordinates the SPO

4            regulatory support function.

5

6    Q.      PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND

7            PROFESSIONAL EXPERIENCE.

8    A.      I joined Gulf States Utilities Company (subsequently, Entergy Gulf States,

9            Inc. (“EGSI”)) in June 1981 as an accountant.          In April 1983, I was

10           transferred to the Regulatory Affairs Department and held a variety of

11           positions     from    September   1986    until   December   1993,    including

12           Supervisor, Rate Regulation; Director, Technical and Administrative

13           Support; Director, Regulation-Louisiana. In January 1994, I joined ESI as

14           Manager, Regulations where I was responsible for coordinating

15           merger-related human resource issues and for ensuring the timely and

16           consistent implementation of related policies. I also provided oversight to

17           all merger-related proceedings. In May 1996, I became a Senior Lead

18           Analyst in the Plant Operations Business Support group where I was

19           responsible for preparing financial analyses and performing other

20           business support functions for the Plant Operations organization.             In

21           January 1997, I moved to the SPO as a Senior Staff Analyst in the

22           Resource Planning Department.            In that role, I was responsible for

23           coordinating all regulatory activities (rate filings, requests for information,




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     Entergy Texas, Inc.                                                      Page 3 of 75
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1            etc.). In December 1998, I became the Manager – Planning Models and

2            Analysis, where I was responsible for producing production costing studies

3            and load and energy forecasts for the Entergy Operating Companies. In

4            February 2004, I became the Manager – Energy Analysis and Reporting,

5            where I was responsible for the preparation of the intra-system bill and the

6            settlement of gas, oil and power transactions for all Entergy Operating

7            Companies.         In February 2008, I became the Director of Supply

8            Procurement and Asset Optimization, where I was responsible for the

9            preparation of long-term requests for proposals and the negotiation of

10           long-term purchased power contracts and power plant acquisitions. In

11           February 2010, I became the Director of Compliance and Business

12           Support, where I was responsible for compliance with the electric reliability

13           standards, and SPO’s budget and information technology departments. In

14           February 2011 I accepted my current role. I graduated from Texas A&M

15           University in 1981 with a Bachelor of Business Administration degree in

16           Finance.      I am a Certified Public Accountant in the State of Texas,

17           Certificate Number 49910.

18

19   Q.      WHAT IS THE PURPOSE OF YOUR TESTIMONY?

20   A.      My testimony has two major purposes:          (1) I support the costs and

21           revenues associated with ETI’s participation in the Entergy System

22           Agreement during the test year of July 1, 2010 to June 30, 2011 (the “Test

23           Year”) and during the fuel-related Reconciliation Period (July 2009 through




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     Entergy Texas, Inc.                                                        Page 4 of 75
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1            June 2011); and (2) I present the Energy and Fuel Management Class of

2            affiliate costs that were billed to ETI during the Test Year. In the first part

3            of my testimony, I discuss how ETI coordinates its generation and bulk

4            transmission functions with the other Entergy Operating Companies via

5            the     Entergy    System      Agreement,   a   Federal   Energy   Regulatory

6            Commission (“FERC”)-approved tariff that includes seven FERC-approved

7            rate schedules.       I will also explain the various Service Schedules and

8            provisions referenced in the Entergy System Agreement. In general, this

9            part of my testimony addresses the box labeled “Intra-System Bill” on

10           Figure MHT-3 of Company witness Michelle H. Thiry’s testimony.

11                    With respect to the second part of my testimony, I demonstrate that

12           costs included in the Energy and Fuel Management Class of affiliate costs

13           that were billed to ETI during the Test Year are necessary and

14           reasonable; that the price charged to ETI for these affiliate services is not

15           higher than the prices charged by ESI for the same item or class of items

16           to other affiliates or non-affiliates; and that these costs represent the

17           actual cost of these services.         I also sponsor certain capital costs

18           associated with the services of the SPO from July 2009 through the end of

19           the Test Year (June 30, 2011).




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     Entergy Texas, Inc.                                                                           Page 5 of 75
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 1        11.           COSTS ASSOCIATED WITH THE ENTERGY SYSTEM AGREEMENT

 2                                                 A.      Summary

 3   Q.            PLEASE SUMMARIZE THE COSTS AND REVENUES INCURRED

 4                 PURSUANT TO THE ENTERGY SYSTEM AGREEMENT THAT ARE

 5                  INCLUDED IN THIS PROCEEDING.

 6   A.            Costs allocated to ETI pursuant to the terms of the Entergy System

 7                 Agreement relate to the following three components of the Company's

 8                 filing:

 9                 •         Reconciliation of Past Costs: With respect to the Company's fuel

1O                           factor, the Company will be reconciling costs incurred under
                                                                            3
11                           Service Schedules MSS-3 and MSS-4, costs allocated to ETI from

12                           Joint Account Purchases, and the net balance from Joint Account

13                           Sales under the terms of Service Schedule MSS-5.

14                  •

15                           sponsors the                                                                    of

16

17

18

19                  •        Base Rates: The Company requests base rate recovery of the Test

20                           Year amount of Service Schedule MSS-2 costs. Additionally, in the

21                           event the Commission does not approve the PPR, Service

     3
                I describe each of these service schedules in more detail later in my testimony.




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1                    Schedule MSS-1 and MSS-4 costs that would have been included

2                    in the PPR would be included in the Company’s base rates.

3

4                              B.      The Entergy System Agreement

5    Q.      WHAT IS THE ENTERGY SYSTEM AGREEMENT?

6    A.      The Entergy System Agreement is a FERC-approved tariff which

7            mandates that the Operating Companies operate as a single, integrated

8            System. As stated in Section 3.01 of the Entergy System Agreement, its

9            purpose is “to provide the contractual basis for the continued planning,

10           construction, and operation of the electric generation, transmission and

11           other facilities of the Operating Companies in such a manner as to

12           achieve economies consistent with the highest practicable reliability of

13           service, subject to financial considerations, reasonable utilization of

14           natural resources and minimization of the effect on the environment.” The

15           Entergy System Agreement also provides a basis for the equalization

16           among the Operating Companies of any imbalances of costs arising from

17           the construction, ownership, or operation of facilities that are used for the

18           collective benefit of all the Operating Companies.

19                   Consistent with the above discussion, the Commission has

20           characterized the Entergy System Agreement as:

21                   the tariff approved by the FERC that provides the basis for
22                   the operation and planning of the Entergy System, including
23                   the [then] five Operating Companies.          The System
24                   Agreement governs the wholesale-power transactions
25                   among the Operating Companies by providing for joint




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     Entergy Texas, Inc.                                                           Page 7 of 75
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1                    operation and establishing the bases for equalization among
2                    the Operating Companies, the costs associated with the
3                    construction ownership and operation of the Entergy System
                                 4
4                    facilities.

5                    The current version of the Entergy System Agreement was entered

6            into on April 23, 1982, and, as subsequently amended, is among ESI and

7            each of the Operating Companies. It was initially approved by the FERC

8            on June 13, 1985, in Opinion No. 234, Middle South Energy, Inc., 31

9            FERC (C.C.H.) ¶ 61,305 (1985). Exhibit PJC-1 is a copy of the current

10           version of the Entergy System Agreement.

11

12   Q.      WHAT ENTITY ADMINISTERS THE ENTERGY SYSTEM AGREEMENT?

13   A.      The tariff states that the overall administration of the Entergy System

14           Agreement is to be carried out by the Entergy Operating Committee.

15           During the Reconciliation Period and Test Year, ETI’s operations were

16           represented on the Operating Committee by Mr. Joseph F. Domino, the

17           President and CEO of Entergy Texas. During the Reconciliation Period

18           and Test Year, the daily administration of the Entergy System Agreement

19           was carried out by the SPO under the direction of the Operating

20           Committee.       The SPO was also responsible for the administration of

21           billings between the Operating Companies in accordance with certain

22           Service Schedules of the Entergy System Agreement.


     4
          Docket No. 32710, Order on Rehearing at 8 (Finding of Fact 39).




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1    Q.      WHAT ARE THE DUTIES OF THE OPERATING COMMITTEE?

2    A.      Section 5.06 of the Entergy System Agreement sets forth the duties of the

3            Operating Committee. In part, those duties include being responsible for

4            the day-to-day administration of the Entergy System Agreement, making

5            decisions with respect to the installation of generation and bulk power

6            transmission facilities, determining the amount and timing of generating

7            reserves sufficient to ensure the reliable supply of capacity and energy to

8            the Operating Companies’ customers, providing supervision for the

9            System Operator, studying and determining additions and changes in

10           facilities necessary to keep abreast of the production and transmission

11           requirements of the System, and coordinating arrangements to procure or

12           sell power outside of the System.       The Entergy System Agreement

13           empowers the Operating Committee to make the key decisions regarding

14           the acquisition and allocation of generating resources and electric energy

15           for the Operating Companies.

16

17   Q.      WHY DO THE OPERATING COMPANIES JOINTLY PLAN AND

18           OPERATE THEIR ELECTRIC SYSTEMS?

19   A.      By jointly planning and operating their electric systems, the Operating

20           Companies are able to aggregate their loads and jointly dispatch their

21           resources to serve that aggregated load. The Entergy System resources

22           are economically dispatched, subject to reliability and operating

23           constraints that exist at any given time, to achieve the lowest cost of




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     Entergy Texas, Inc.                                                                Page 9 of 75
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1            energy for the combined System as a whole. The aggregation of load and

2            resources into a single system means that the combined resources of the

3            Operating Companies can be optimally dispatched, allowing each

4            Operating Company’s load to be supplied with the most economical

5            resources available to the System. In addition, the Operating Companies

6            experience increased reliability on both a planning and an operating basis

7            as a result of coordinated operations. Through the combined reliance on

8            many      diverse     generating     units,   fuel   sources,    and      bulk   power

9            interconnections, each Operating Company is better protected from

10           service interruptions or disturbances caused by the loss of generating

11           units, fuel supply disruptions, and/or transmission outages or constraints.

12                   The FERC recognized the benefits of System-wide planning and

13           operations in its Opinion 234-A (Order Denying Rehearing and Granting

14           Interventions), wherein the FERC held:

15                   We reaffirm that the Middle South [now Entergy] companies
16                   appropriately approach power planning on a systemwide
17                   basis, whereby the individual companies’ needs are the
18                   component parts of the System power plan. Implementation
19                   of the System plan, however, requires that the individual
20                   companies’ needs be subsumed by the greater interest of
                                       5
21                   the entire system.

22                   This finding by the FERC was quoted with approval by the United
                                            6
23           States Supreme Court.              This confirms that planning and operating


     5
         32 F.E.R.C. ¶ 61,425 at 61,958 (1985).
     6
         Miss. Power & Light v. Miss. Ex. Rel. Moore, 487 U.S. 354, 376,108 S.Ct. 2428, 2441 (1988).




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     Entergy Texas, Inc.                                                                Page 10 of 75
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1            decisions were and are to be made on a system-wide basis for the benefit

2            of the System as a whole, recognizing the fact that such system-wide

3            basis for decisions might cause the interests of an individual Operating

4            Company in a particular decision to be outweighed by the overall good of

5            the System over time.

6

7    Q.      PLEASE        EXPLAIN          HOW   THE     COSTS        OF    PROVIDING         AND

8            TRANSMITTING THE ELECTRICITY TO SERVE THE AGGREGATED

9            SYSTEM’S LOAD ARE ALLOCATED AMONG THE OPERATING

10           COMPANIES.

11   A.      These costs are allocated pursuant to the terms of the Entergy System

12           Agreement and its Service Schedules, which I describe below.                       The

13           Supreme Court has held that FERC's exclusive jurisdiction applies to

14           power allocations that affect wholesale rates. It is my understanding that

15           these allocations are binding on States, and States must treat those
                                                                                         7
16           allocations as fair and reasonable when determining retail rates.




     7
          See Entergy Louisiana, Inc. v. Louisiana Public Service Commission, 539 U.S. 39, 123 S. Ct.
          2050 (2003); Mississippi Power v. Miss. Ex. Rel. Moore, 487 U.S. 354, 371, 108 S. Ct. 2428,
          2441 (1988).




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     Entergy Texas, Inc.                                                      Page 11 of 75
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1    Q.      WHAT ARE THE SERVICE SCHEDULES ASSOCIATED WITH THE

2            ENTERGY SYSTEM AGREEMENT?

3    A.      There are seven Service Schedules, each of which is a FERC-filed rate

4            schedule, associated with the Entergy System Agreement. They are:

5                    MSS-1 - Reserve Equalization;

6                    MSS-2 - Transmission Equalization;

7                    MSS-3 - Exchange of Electric Energy Among the Companies;

8                    MSS-4 - Unit Power Purchase;

9                    MSS-5 - Distribution of Revenue from Sales Made for the Joint

10                            Account of All Companies;

11                   MSS-6 - Distribution of Operating Expenses of System Operations

12                            Center; and

13                   MSS-7 - Merger Fuel Protection Procedure.

14

15   Q.      PLEASE DESCRIBE SERVICE SCHEDULE MSS-1.

16   A.      Service Schedule MSS-1 (which is called “Reserve Equalization” in the

17           Entergy System Agreement) prescribes a method for sharing some of the

18           fixed costs of generating capability among Operating Companies. One of

19           the benefits of participating in a pooling arrangement such as the Entergy

20           System Agreement is the ability to rely on System reserves. (The term

21           “reserves” in this context refers to the difference between MW of capability

22           and MW of peak load; it can be measured either for the System or for an

23           Operating Company.) Each Operating Company owns or controls its own




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     Entergy Texas, Inc.                                                        Page 12 of 75
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1            capability, but all Companies can draw upon the aggregate capability of

2            the System in determining the adequacy of reserves. However, some

3            Operating Companies own more than their share of the System’s total

4            capability relative to their load, and thus own more than their share of

5            System reserves. Other Companies own less than their share. These

6            Operating Companies are known as “long” and “short” Operating

7            Companies, respectively.          “Long” Companies are those with more

8            generation capability, relative to their monthly peak load.             “Short”

9            Companies are those with less generation relative to their monthly peak

10           load. A company’s position and the extent to which it is “long” or “short”

11           can change over time. The Service Schedule MSS-1 formula provides for

12           payments by “short” Companies to “long” Companies.

13

14   Q.      WHAT       IS    THE      BASIS   FOR   DETERMINING      AN       OPERATING

15           COMPANY’S SHARE OF SYSTEM RESERVES?

16   A.      An Operating Company’s share of System reserves is determined using a

17           concept defined in the Entergy System Agreement as “Responsibility

18           Ratio,” which is an allocator that reflects the relative contribution of each

19           Operating Company to the System’s coincident peak load – in other

20           words, an Operating Company’s coincident peak load divided by the

21           System peak load, calculated on a rolling twelve-month average.             An

22           Operating Company’s share of System reserves is the product of that




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     Entergy Texas, Inc.                                                            Page 13 of 75
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1            Operating Company’s Responsibility Ratio and the total level of

2            System reserves.

3

4    Q.      HOW ARE MSS-1 PAYMENTS DETERMINED?

5    A.      A short Company makes a payment only for the MW by which it is “short.”

6            The payments are computed monthly by multiplying the Company’s MW

7            shortfall times a $/MW rate for the cost of owning reserve capability. The

8            rate is based on the fixed operating cost of certain oil- and gas-fired

9            generating units owned by the “long” Companies .

10

11   Q.      ARE      RESERVE          EQUALIZATION          PAYMENTS       DISCRETIONARY

12           AMONG THE OPERATING COMPANIES?

13   A.      No. The FERC-approved Entergy System Agreement mandates that the

14           Operating Companies make and receive Reserve Equalization payments

15           in accordance with Service Schedule MSS-1.

16                   In a prior ETI reconciliation case, the Commission found:

17                   By approving Service Schedule MSS-1, the FERC has
18                   approved the method by which the Operating Companies
19                   share the cost of maintaining sufficient reserves to provide
                                                                    8
20                   reliability for the Entergy System as a whole.




     8
          Docket No. 32710, Order on Rehearing at 9 (Finding of Fact 42).




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     Entergy Texas, Inc.                                                      Page 14 of 75
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1    Q.      DOES       ETI    PAY     ANY   MORE    FOR   RESERVE     EQUALIZATION

2            PAYMENTS MADE PURSUANT TO SERVICE SCHEDULE MSS-1 THAN

3            ANY OTHER OPERATING COMPANY?

4    A.      No. Service Schedule MSS-1 is a formula rate, and ETI’s payments or

5            receipts in any particular month will be the same as any other similarly

6            situated Operating Company. In any given month, all of the Operating

7            Companies that are “short” and which must make MSS-1 payments will

8            pay the same rate, based on a weighted average of the rates for each of

9            the “long” Operating Companies, for each MW of capability for which it

10           is responsible.

11

12   Q.      DO      RESERVE          EQUALIZATION    PAYMENTS       RESULT        FROM

13           RESOURCES REQUIRED TO MEET THE ENTERGY SYSTEM’S LOAD

14           REQUIREMENTS?

15   A.      Yes. As I explained above, the Entergy System is planned and operated

16           as a single, integrated electric system to satisfy the combined load

17           requirements of the Operating Companies.         An essential element of

18           providing reliable and efficient delivery of electricity to customers is

19           maintaining an adequate level of capability through ownership or control of

20           generation.      ETI’s Reserve Equalization payments reflect its allocated

21           share of the cost of maintaining adequate capability for the System as

22           a whole.




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     Entergy Texas, Inc.                                                           Page 15 of 75
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1    Q.      WHERE ARE SERVICE SCHEDULE MSS-1 AMOUNTS IDENTIFIED IN

2            THIS PROCEEDING?

3    A.      Amounts allocated pursuant to Service Schedule MSS-1 are shown in

4            Schedule H-12.4 a-g. Mr. Cooper, in his Exhibit RRC-1, identifies the total

5            rate year amount of Service Schedule MSS-1 costs sought to be included

6            in rates.

7

8    Q.      PLEASE DESCRIBE SERVICE SCHEDULE MSS-2.

9    A.      Service Schedule MSS-2 prescribes the method for equalizing the

10           ownership costs associated with certain transmission systems facilities

11           owned and operated by each Operating Company.                Service Schedule

12           MSS-2        determines        each   Operating    Company’s         Transmission

13           Responsibility      by    summing     the   System’s   Net   Inter-Transmission

14           Investments and multiplying that total by each Operating Company’s

15           Responsibility Ratio.

16

17   Q.      HOW ARE THE PAYMENT AMOUNTS FOR SERVICE SCHEDULE

18           MSS-2 DETERMINED?

19   A.      Each Operating Company’s Net Inter-Transmission Investment is

20           subtracted from its Transmission responsibility. The result is multiplied by

21           the System Average Ownership Cost (“AOC”) in order to calculate the

22           amount that each Operating Company should pay or receive each month.

23           The AOC develops ownership costs of certain transmission investments.




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     Entergy Texas, Inc.                                                           Page 16 of 75
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1    Q.      HOW IS THE AOC DETERMINED?

2    A.      The AOC rate consists of capital costs, federal and state income tax rates,

3            and operating expenses scaled by investment costs. Section 20.06 of the

4            Entergy System Agreement shows the AOC formula. This formula uses

5            financial factors similar to those used in the Service Schedule MSS-1
                            9
6            calculation.

7

8    Q.      ARE TEST YEAR SERVICE SCHEDULE MSS-2 EXPENSES INCLUDED

9            IN ETI’S COST OF SERVICE?

10   A.      Yes. ETI’s MSS-2 expenses are identified in Schedule A as discussed by

11           Company witness Michael P. Considine.

12

13   Q.      HAS THE COMMISSION PREVIOUSLY CONSIDERED SERVICE

14           SCHEDULE MSS-2 PAYMENTS?

15   A.      Yes. In its Second Order on Rehearing dated October 13, 1998, in Docket

16           No. 16705, Finding of Fact No. 96N, the Commission stated:

17                   The FERC has approved the relevant parts of the ESA
18                   (Entergy System Agreement) as amended to reflect the
19                   inclusion of EGS. In Opinion No. 385, the FERC expressly
20                   accepted an amendment to the ESA which added Gulf
21                   States to the ESA as an operating subsidiary. EGS’ MSS-2
22                   expenses are therefore mandated by the FERC.




     9
          Service Schedule MSS-2 billing parameters are in effect from June 1 to the succeeding
          May 31 based on the preceding year’s results.




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     Entergy Texas, Inc.                                                      Page 17 of 75
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1                    Furthermore, as the Commission ordered in Docket No. 16705,

2            Conclusion of Law No. 11D, "under Mississippi Power & Light Co. v.

3            Mississippi, 487 U.S. 354, 369-370, 108 S.Ct. 2428 (1988), a state utility

4            commission must treat FERC-mandated system agreement payments as

5            reasonably incurred operating expenses for the purpose of setting retail

6            rates." The Commission went on to say that Mississippi Power & Light

7            Co. preempts the Commission from disallowing Service Schedule MSS-2

8            expenses.

9

10   Q.      PLEASE DESCRIBE SERVICE SCHEDULE MSS-3.

11   A.      Service Schedule MSS-3 serves two functions.         It first mandates how

12           energy will be allocated and priced among the Operating Companies. The

13           second function is to provide for payments and receipts in accordance

14           with the provisions of Opinion Nos. 480 and 480-A.

15

16   Q.      IS THERE A FUNDAMENTAL PRINCIPLE AT WORK BEHIND THE

17           OPERATION OF SERVICE SCHEDULE MSS-3 AS IT RELATES TO

18           ENERGY ALLOCATION?

19   A.      Yes. The fundamental principle of the Entergy System Agreement is that,

20           subject to the operational and reliability constraints imposed on the

21           System, the lowest-cost resources available to the System Dispatcher are

22           the first resources used to meet the aggregate System load, without

23           regard to which Operating Company owns the resource or which




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     Entergy Texas, Inc.                                                     Page 18 of 75
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1            Operating Company’s load is being served.          Although the economic

2            dispatch of the entire System will result in total System generation output

3            matching total System load, in any given hour the generating output of

4            some Operating Companies will be greater than their individual load, and

5            the generating output of other Operating Companies will be less than their

6            individual load. Therefore, after the System is economically dispatched,

7            an energy accounting process is conducted to, in effect, have the

8            Operating Companies that are “short” on energy in an hour compensate

9            the “long” Companies for the energy that was used to meet the short

10           Companies’ needs.

11                   Because this calculation is performed for each hour, in any given

12           hour, an Operating Company may either be taking exchange energy or

13           supplying exchange energy, but not both.           This exchange energy

14           accounting is set out in Service Schedule MSS-3.

15

16   Q.      HOW DOES SERVICE SCHEDULE MSS-3 WORK WITH RESPECT TO

17           THE OPERATIONS OF EXCHANGE ACCOUNTING?

18   A.      Service Schedule MSS-3 allocates all of the System’s energy resources

19           among the Operating Companies. Under MSS-3, an Operating Company

20           retains the energy (and the associated costs) actually produced from its

21           lowest-cost resources if those resources are needed to meet the loads of

22           its customers.       Only after the needs of an Operating Company’s own

23           customers have been met will the excess energy that the Operating




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     Entergy Texas, Inc.                                                     Page 19 of 75
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1            Company generated in a particular hour, and the associated costs, be

2            allocated to other Operating Companies. This allocation of excess energy

3            pursuant to Service Schedule MSS-3 is referred to as “Exchange Energy”

4            or “Pool Energy.” Operating Companies whose resources provided an

5            amount of energy that was greater than their load in an hour furnish

6            energy to the Entergy Energy Exchange (the “Exchange”), and

7            Companies whose load is greater than the amount of energy provided by

8            their resources in an hour are allocated energy from the Exchange.

9            However, it is important to note that, in total, MSS-3 is a zero-sum game.

10           The sum of the MSS-3 payments and receipts for all of the Operating

11           Companies for any individual hour is zero.

12

13   Q.      HOW IS THE MSS-3 ACCOUNTING PERFORMED?

14   A.      Service Schedule MSS-3 is an automated, after-the-fact allocation

15           mechanism. That allocation of energy and associated costs required by

16           the System Agreement is performed within a computer program known as

17           the Intra-System Bill. For a more detailed discussion of the ISB, see the

18           next section.

19                   The process that is used to allocate System energy is sometimes

20           known as a “stacking” process. An example of the stacking process is

21           shown in the following Figure PJC-1. As may be seen in that example, the

22           underlying process is to stack the amount of energy produced by each

23           Operating Company’s resources from lowest cost to highest cost in




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     Entergy Texas, Inc.                                                     Page 20 of 75
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1            separate stacks for each Operating Company. Then, again within each

2            hour, the amount of energy resources within each Operating Company’s

3            stack is compared to the amount of energy consumed by its customers. If,

4            for an individual company, the amount of energy produced is greater than

5            the amount of energy used by its customers, the energy (and associated

6            costs) at the top end of the stack (in essence, above the level needed for

7            that Company’s own customers) is allocated to the Exchange.                A

8            Company whose resources produced less energy than the amount of

9            energy its own customers used is allocated the deficit amount of energy

10           from the Exchange. Each of these transactions occurs at cost. Operating

11           Companies that have excess energy that is allocated to the Exchange

12           receive a payment, as defined in Section 30.08 of the Entergy System

13           Agreement, that is based on average fuel costs (plus an O&M- and SO2 -

14           based adder), and the Companies that have energy allocated to them

15           from the Exchange pay the weighted average cost of all of the energy

16           allocated to the Exchange in that hour.




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     Entergy Texas, Inc.                                                          Page 21 of 75
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                                            Figure PJC - 1
                           MSS - 3 EXCHANGE ENERGY ACCOUNTING EXAMPLE
                     Stack by
                                           ILLUSTRATIVE
                     cost;
                    Allocate
                   excess, at
                  cost, to the                                               Exchange
                   Exchange                                                 Purchase at
                                                                             $40/MWH

                  Company 1                  Gas at
                    Gas at                  $60/MWH
                   $60/MWH                             Company 2
                                                         Gas at
                                                        $75/MWH              Allocate at
                                             Coal at                        average cost
                                            $20/MWH                              of
          MW                                                                 Exchange
                                                                              Energy
                  Company 1
                    Coal at
                   $20/MWH
                                                       Company 2
                                                         Coal at
                                                        $25/MWH


                  Company 1                            Company 2
                  Nuclear at                           Nuclear at
                   $10/MWH                              $10/MWH


                  Resources      Load      To          Resources    Load       From
                                        Exchange                             Exchange



                     Operating Company 1                Operating Company 2




1    Q.        HAS THE COMMISSION PREVIOUSLY ADDRESSED WHETHER

2              COSTS INCURRED BY ETI UNDER SERVICE SCHEDULE MSS-3 ARE

3              REASONABLE?

4    A.        Yes. In its Order on Rehearing in Docket No. 15102, the Commission

5              addressed costs incurred under Service Schedule MSS-3 in the following

6              Findings of Fact:




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1            202. Schedule MSS-3 of the ESA (Entergy System Agreement)

2                    determined the pricing and exchange of energy among EGS and

3                    the affiliate EOCs (Entergy Operating Companies) during the

4                    reconciliation period.

5            203.    By approving Schedule MSS-3 and the ESA, the Federal Energy

6                    Regulatory Commission (FERC) has determined how the EOCs will

7                    be reimbursed for energy sold to the exchange pool and how the

8                    EOCs,       including    EGS,    will   purchase      energy     from    the

9                    exchange pool.

10           207.    The FERC has determined that the ESA and Schedule MSS-3 is a

11                   just and reasonable way of allocating energy costs and revenues

12                   among the EOCs, including EGS, and has determined that the

13                   charges imposed on EGS by operation of the ESA are fair and

14                   reasonable in comparison to the charges imposed on the

15                   other EOCs.

16           As these Findings of Fact demonstrate, the Commission has already

17           concluded that costs incurred pursuant to Service Schedule MSS-3
                                10
18           are reasonable.




     10
          See also Docket No. 15102, Proposal for Decision at 94-96; Docket No. 16705, Second
          Order on Rehearing at 138 (Conclusion of Law 11D); Docket No. 32710, Order at 9 (Finding
          of Fact 43).




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1    Q.      ARE THE COSTS THAT ETI INCURS UNDER SERVICE SCHEDULE

2            MSS-3 ANY MORE THAN THE COSTS INCURRED BY ANY OTHER

3            ENTERGY          OPERATING     COMPANY      UNDER       THAT       SERVICE

4            SCHEDULE?

5    A.      No. ETI incurs the exact same cost per kWh for energy from the Service

6            Schedule MSS-3 Exchange pool as does any other Entergy Operating

7            Company that is allocated energy from the Service Schedule MSS-3

8            Exchange in the same hour.

9

10   Q.      ARE SERVICE SCHEDULE MSS-3 EXPENSES INCLUDED IN THIS

11           CASE?

12   A.      Yes.     Service Schedule MSS-3 Exchange revenue and expense is

13           identified in Schedules H-12.4 a-g and H-12.5 b-e.

14

15   Q.      ARE ANY OTHER TRANSFERS OF ENERGY GOVERNED BY SERVICE

16           SCHEDULE MSS-3?

17   A.      Yes. The allocation of energy for sales to off-system companies made for

18           the joint account of all the Operating Companies (Joint Account Sales) is

19           made pursuant to Service Schedule MSS-3.             According to Service

20           Schedule MSS-3, any costs incurred by the Operating Companies whose

21           sources supplied the sale are paid out of the gross revenue received for

22           such sales.       Then, the remaining revenue from such sales (the “net




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     Entergy Texas, Inc.                                                        Page 24 of 75
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1            balance”) is divided among the Operating Companies in accordance with

2            Service Schedule MSS-5.

3

4    Q.      PLEASE DESCRIBE SERVICE SCHEDULE MSS-4.

5    A.      Service Schedule MSS-4 prescribes a method for determining the

6            payment for a unit power purchase between Operating Companies and/or

7            the sale of power purchased by another Operating Company.               A unit

8            power purchase is defined as the purchase of a portion of a Designated

9            Generating Unit’s capability, which entitles the purchaser to receive each

10           hour that portion of the total energy generated by that unit.

11

12   Q.      PLEASE EXPLAIN HOW AFFILIATED POWER PURCHASES ARE

13           MADE PURSUANT TO SERVICE SCHEDULE MSS-4.

14   A.      An Operating Company may enter into a resource-specific power

15           transaction with another Operating Company pursuant to Service

16           Schedule MSS-4. Service Schedule MSS-4 is a cost-based formula rate

17           that bills the buyer a monthly per-kilowatt rate relating to the non-fuel cost

18           and a per kWh rate relating to the actual energy cost for the participating

19           unit subject to the transaction. During the term of a Service Schedule

20           MSS-4 transaction, the resource is considered to be under the control of

21           the purchasing Operating Company for purposes of cost responsibility and

22           allocation of energy under the Entergy System Agreement.




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     Entergy Texas, Inc.                                                           Page 25 of 75
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1    Q.       HAS THE COMMISSION ADDRESSED SERVICE SCHEDULE MSS-4

2             COSTS?

3    A.       Yes. The Commission previously recognized:

4                     Service Schedule MSS-4 of the System Agreement sets
5                     forth the method for determining the payment for unit power
6                     purchases between Operating Companies. By approving
7                     Service Schedule MSS-4, the FERC has approved the
8                     methodology for pricing Inter-Operating Company unit power
                                 11
9                     purchases.

10

11   Q.       ARE THE RATES PAID BY ETI UNDER SERVICE SCHEDULE MSS-4

12            ANY MORE THAN THE RATES CHARGED TO ANY OTHER ENTERGY

13            OPERATING COMPANY UNDER THAT SERVICE SCHEDULE?

14   A.       No. Service Schedule MSS-4 is a cost-based formula rate. That same

15            formula rate is applied to each Service Schedule MSS-4 transaction

16            between Operating Companies.              The cost structure for the underlying

17            resource will be unique to each resource, but the rate charged is the same

18            for all Operating Companies.

19

20   Q.       ARE SERVICE SCHEDULE MSS-4 AMOUNTS ADDRESSED IN THIS

21            PROCEEDING?

22   A.       Yes. Service schedule MSS-4 energy and capacity costs are identified in

23            Schedule H-12.4 a-g. For purposes of this proceeding MSS-4 contracts


     11
          Docket No. 32710, Order at 9 (Finding of Fact 44).




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1            have been labeled as either “legacy” (those transactions involving the

2            purchase of power from generating resources owned by ETI’s

3            predecessor, Entergy Gulf States, Inc.), or “other” (all other MSS-4

4            transactions).

5

6    Q.      PLEASE DESCRIBE SERVICE SCHEDULE MSS-5.

7    A.      Service Schedule MSS-5 prescribes the method for distributing the net

8            balance from Joint Account Sales, which are wholesale sales to third

9            parties made by the System on behalf of all of the Operating Companies.

10           The System makes such sales when they can be made at a price that is

11           expected to exceed the System’s incremental cost. As mentioned above,

12           in accordance with Service Schedule MSS-3, any costs associated with

13           these Joint Account Sales first are deducted from the gross revenue

14           received for such sales and distributed to the Operating Companies

15           whose sources supplied the sale. Service Schedule MSS-5 provides that

16           the remainder of the revenues or deficit in revenues (the “Net Balance”) is

17           distributed among the Operating Companies in proportion to the

18           Responsibility Ratio of each Operating Company.

19

20   Q.      ARE SERVICE SCHEDULE MSS-5 REVENUES INCLUDED IN THIS

21           CASE?

22   A.      Yes. Those revenues shown in Schedule H-12.5 b-e are credited to ETI’s

23           fuel balance as revenues from off-system sales.




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1    Q.      PLEASE DESCRIBE SERVICE SCHEDULE MSS-6.

2    A.      Service Schedule MSS-6 sets forth a method by which the costs incurred

3            in providing and operating the System Operations Center may be

4            distributed among the Entergy Operating Companies. During the Test

5            Year, these costs were included in the ESI affiliate billings.

6

7    Q.      PLEASE DESCRIBE SERVICE SCHEDULE MSS-7.

8    A.      Service Schedule MSS-7 is entitled “Merger Fuel Protection Procedure”

9            and resulted from the merger between Gulf States Utilities Company and
                        12
10           Entergy.        This service schedule expired by its own terms prior to the

11           Reconciliation Period.

12

13   Q.      DOES THE ENTERGY SYSTEM AGREEMENT PERMIT PURCHASES

14           OF POWER FROM THE WHOLESALE MARKET?

15   A.      Yes. In particular, the Entergy System Agreement addresses wholesale

16           market purchases in Sections 5.06(p), 4.02 and 4.03. Section 5.06(p) of

17           the Entergy System Agreement requires the Operating Committee to

18           coordinate the procurement of power for one or more of the Operating

19           Companies for either reliability or economic purposes.




     12
          Gulf States Utilities Company was renamed Entergy Gulf States, Inc. and was subsequently
          separated into EGSL and ETI.




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1                    Section     4.02       of   the   Entergy   System   Agreement,    entitled

2            “Purchased Capacity and Energy,” empowers the Operating Committee to

3            specify the conditions under which one or more individual Operating

4            Companies can purchase capacity for their own account, which is then

5            treated as a resource included in the purchasing Company’s (or

6            Companies’) capacity as if it was an owned resource.               Generally, as

7            described in more detail in Company witness Robert R. Cooper’s

8            testimony, the Operating Committee has adopted a broad set of planning

9            principles and objectives that drive the resource allocation process.

10           However, the factors that the Operating Committee considers when

11           evaluating the allocation of limited or long-term resources – such as

12           System reliability, relative production costs, and the match between an

13           Operating Company’s load profile and the mix of supply types – are rooted

14           in the requirements of, among others, Sections 3.01 and 3.05 of the

15           Entergy System Agreement.                 All of the power purchase agreements

16           discussed in Company witness Cooper’s testimony were purchased

17           pursuant to Section 4.02 of the Entergy System Agreement.

18                   Section 4.03, “Energy Purchased by Services,” of the Entergy

19           System Agreement dictates when and how ESI may make purchases from

20           third parties on behalf of the Operating Companies. It provides that ESI

21           “may purchase energy under economic dispatch or emergency conditions

22           for the joint account of all the Operating Companies.                  The energy

23           purchased shall be allocated to each Operating Company in proportion to




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1            its Responsibility Ratio in effect at the end of the preceding month.” Most

2            of the purchases described in the testimony of Company witness Michelle

3            H. Thiry, especially those purchases with a term of one month or less, are

4            such purchases that are made for the benefit of the System when ESI,

5            who is delegated the authority under the Entergy System Agreement to

6            make the purchases, deems such purchases economical or necessary.

7            When such purchases are made for the joint account of all the Operating

8            Companies, ETI is allocated its Responsibility Ratio share of all of those

9            purchases in each hour.

10

11   Q.      DOES       THE     ENTERGY     SYSTEM     AGREEMENT       PROVIDE        THE

12           OPERATING COMPANIES ANY DISCRETION IN ACCEPTING AN

13           ALLOCATED PORTION OF PURCHASES?

14   A.      No.     The Operating Companies are required to take their respective

15           allocated share of purchased power because those purchases arise out of

16           the joint economic dispatch of the System. Each Operating Company

17           must bear responsibility for its share of purchases made for the benefit of

18           the System.        Moreover, the joint planning obligations of the Entergy

19           System Agreement require each Operating Company to accept its

20           allocated share of purchased capacity and energy, when so allocated by

21           the Operating Committee.




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     Entergy Texas, Inc.                                                     Page 30 of 75
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1    Q.      ARE THE PURCHASES ALLOCATED TO ETI ALWAYS USED TO

2            SERVE ETI’S CUSTOMERS’ NEEDS?

3    A.      No, not necessarily. ETI’s allocated share of purchases is considered an

4            ETI source for the purposes of allocating energy and costs under Service

5            Schedule MSS-3. Therefore, in any given hour, if ETI has resources in

6            excess of its needs and a wholesale power purchase is among the lowest

7            cost resources, that purchase stays with ETI’s customers for that hour.

8            However, if ETI has resources in excess of its needs and its allocated

9            share of a purchase is more costly than other ETI resources, ETI’s

10           allocated share of the purchase is assigned to the Exchange for that hour,

11           for which ETI is compensated.

12

13   Q.      CAN ETI EVER RECEIVE MORE THAN ITS ALLOCATED SHARE OF A

14           PURCHASE?

15   A.      No, not directly. However, as described above, purchases are treated as

16           an Operating Company resource under Service Schedule MSS-3.

17           Therefore, if ETI’s needs were in excess of its resources in any given hour

18           and thus ETI was purchasing energy from the Exchange, it may receive

19           some purchased energy that was originally allocated to another Entergy

20           Operating Company that later flowed through the Exchange. However,

21           under the terms of the Entergy System Agreement, such allocations are

22           considered to be from the Exchange and are not considered a Joint

23           Account Purchase allocation.




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     Entergy Texas, Inc.                                                                     Page 31 of 75
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1         C.       Billing for Entergy System Agreement-Related Revenues and Costs

2    Q.        HOW ARE OPERATING COMPANIES BILLED FOR THE COSTS

3              INCURRED PURSUANT TO THE ENTERGY SYSTEM AGREEMENT?

4    A.        The Operating Companies are billed through a monthly Intra-System
                           13
5              Bill (“ISB”).

6

7    Q.        WHAT IS THE ISB?

8    A.        The ISB is a program that creates inter-company invoices prepared by

9              ESI. The ISB details the costs to be paid and revenues to be received by

10             each Operating Company for the transactions that occurred pursuant to

11             the Entergy System Agreement.

12

13   Q.        HOW IS THE ISB PREPARED?

14   A.        The ISB is prepared by a custom computer program that incorporates the

15             algorithms specified in the Entergy System Agreement.                      On an hourly

16             and/or daily basis, fuel cost, unit generation, Operating Company load,

17             and wholesale transactions data are collected and compiled into the ISB’s

18             database records.




     13
          The Intra-System Bill is distinct from the intra-system affiliate billing process discussed in the
          Direct Testimony of Company witness Stephanie B. Tumminello.




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1    Q.      HOW IS THE MONTHLY ISB ORGANIZED?

2    A.      The monthly ISB is divided into attachments, with each attachment

3            containing multiple pages, if necessary.          These are the current

4            attachments, as of July 2010:

5                   Attachment 1 - kWh Disposition by Operating Company, Joint

6                    Account Purchases and Individual Company Purchases by

7                    Operating Company;

8                   Attachment 2 - Exchange Energy (to/from), Unit power Purchases,

9                    AECC Excess Energy;

10                  Attachment 3 - Joint Account Sales and Net Balance;

11                  Attachment 4 - Peak Load Data and Responsibility Ratios;

12                  Attachment 5 – Owned or Contracted Capacity, Reserve &

13                   Transmission Equalization;

14                  Attachment 6 - Operating Company Summaries and System Total;

15                  Attachment 11 – Summary of Joint Account Purchases and

16                   Individual Company Purchases; and

17                  Attachment 12 - Fiber Optics Equalization.

18

19   Q.      PLEASE        BRIEFLY          DESCRIBE   EACH   ATTACHMENT      OF    THE

20           MONTHLY ISB.

21   A.      Attachment 1 shows the monthly totals of energy allocated to each

22           Operating Company by source and the disposition of that energy.




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     Entergy Texas, Inc.                                                        Page 33 of 75
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1                    This attachment shows the allocation of kWh from each Operating

2            Company’s own sources (net generation and off-system purchases) to

3            each Operating Company’s net area, to the Exchange, to inadvertent

4            energy or to sales. It also shows Joint Account Purchases allocated to

5            each Operating Company based on Responsibility Ratios. Toward the

6            end of Attachment 1 is a one-page summary of the allocation of the total

7            kWh for each Operating Company and for the total System and a

8            summary listing the allocation to each Operating Company of purchases

9            made during the month.

10                   Attachment 2 is a summary, by Operating Company, of the kWh

11           and the associated cost of the sources furnishing energy to the Exchange

12           during that month.             Only Operating Companies furnishing Exchange

13           energy during the month are included in this section of Attachment 2.

14           Following the summary of sources by each Operating Company furnishing

15           energy to the Exchange is a summary, by Operating Company, of the

16           allocations of energy from the Exchange during the month. This page lists

17           each Operating Company, the kWh allocated to it during the month, the

18           total dollars charged for those allocations, and the average cost of the

19           kWh allocated.        Each Operating Company that is allocated Exchange

20           energy in a given hour pays the same price per kWh for that energy;

21           however, this summary is prepared on a monthly basis, so the dollars per

22           kWh paid by each Operating Company will necessarily be different. For




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     Entergy Texas, Inc.                                                     Page 34 of 75
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1            example, consider the following data contained in Attachment 2 in the July

2            2010 ISB that is attached as Exhibit PJC-2.

                                            Figure PJC-2
                                              July 2010

             Company                KWh          Charge ($)         Average Charge
                                                                       (mills/KWh)
             EAI                   131,563,443     8,545,539.76           64.95
             ELL                    42,272,082     2,134,170.65           50.49
             EMI                   165,417,337 10,587,664.98              64.01
             ENOI                   45,025,369     2,623,552.75           58.27
             EGSL                     8,681,301      328,900.36           37.89
             ETI                   328,392,353 19,143,734.58              58.30
             Total                 721,351,885 43,363,563.08              60.11
                            Note: Dollars may not add due to rounding.

3                    As may be seen, the use of averages can be misleading. The

4            average cost for the total of all of the Operating Companies for this month

5            is $60.11/MWh. ELL, ENOI, EGSL, and ETI pay less than the average

6            cost, but EAI and EMI pay more.          However, in each of the hours

7            comprising the average, each Operating Company allocated energy from

8            the Exchange paid exactly the same price for that energy.

9                    The next page shows the energy amounts sold to each Operating

10           Company under service schedule MSS-4. At the end of Attachment 2 is a

11           summary of the kWh and dollars allocated to each Operating Company

12           from the Arkansas Electric Cooperative Corporation (“AECC”) excess

13           energy purchase. The kWh from this purchase are allocated using the

14           previous month’s responsibility ratio, as specified in the Entergy

15           System Agreement.




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     Entergy Texas, Inc.                                                                Page 35 of 75
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1                    Attachment       3     relates   to   off-system   Joint    Account      Sales.

2            Attachment 3 lists the purchasing entity, type of sale, total kWh sold, total

3            dollars charged, and the average cost for each sale.               Next is a listing of

4            the sources used by each Operating Company to supply the off-system

5            Joint Account Sales during the month, the kWh supplied, and the cost that

6            the Operating Companies were credited for having supplied the energy.

7            Next is a summary of the off-system Joint Account Sales, sources

8            supplying the sales. The next page reflects revenue from the sales and

9            the calculated net balance, profit or loss, from the sales.

10                   Attachment 4 shows the monthly coincident peak loads for the

11           previous twelve months and shows the calculation of responsibility ratios.

12                   Attachment 5 reflects the owned or contracted MW ratings for each

13           Operating Company. These ratings are approved by Entergy’s Operating

14           Committee for the purpose of calculating Reserve Equalization (MSS-1).

15                   Attachment 6 is a summary of transactions for each of the

16           Operating Companies.              It shows the Purchases and Sales from

17           Associated Companies, including Exchange energy and dollars and Unit

18           Power Purchases, Sales to Non-Associated Companies (Joint Account

19           Sales), Purchases from Non-Associated Companies (Joint Account

20           Purchases), and Other Revenues or Costs, including Transmission

21           Service Revenue.

22                   Attachment 11 is a monthly summary of the joint account

23           purchases by Seller and Contract Name/Type indicating the net payable




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1            for each Operating Company.          Each entry shows the breakdown of

2            energy, dollars, and an average cost of the purchase(s) by Operating

3            Company. Attachment 11 also shows the allocation of capacity charges

4            for purchased power contracts by contract and by Operating Company.

5                    Attachment 12 is a summary of the fiber optics equalization.

6            Billings under this Attachment are not part of the Entergy System

7            Agreement, and are included in the ISB only as a convenience.

8

9    Q.      IS IT YOUR OPINION THAT THE ISB PROPERLY IMPLEMENTS THE

10           ALLOCATION OF COSTS PURSUANT TO THE ENTERGY SYSTEM

11           AGREEMENT?

12   A.      Yes, the ISB properly implements the FERC-approved allocation of costs

13           among the Operating Companies as specified in the Entergy System

14           Agreement.

15

16   Q.      CAN THE COSTS ALLOCATED THROUGH THE ISB BE REVISED

17           SOLELY FOR THE BENEFIT OF A SINGLE OPERATING COMPANY OR

18           JURISDICTION?

19   A.      Any revision to the allocation of energy and/or costs reflected in an ISB

20           will necessarily affect the other Operating Companies.                    It is my

21           understanding that FERC is the only regulatory authority with jurisdiction

22           to review the multi-jurisdictional effects of such a revision.




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     Entergy Texas, Inc.                                                         Page 37 of 75
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1           III.     THE ENERGY AND FUEL MANAGEMENT CLASS OF COSTS

2    Q.      WHAT IS THE RELATIONSHIP BETWEEN THE SPO ORGANIZATION

3            AND THE ENERGY AND FUEL MANAGEMENT CLASS OF SERVICES

4            THAT YOU SPONSOR?

5    A.      Exhibits PJC-3 and PJC-4 show the division of affiliate classes.            The

6            Generation Function is one of the Functions in the Operations Family of

7            affiliate services (Exhibit PJC-3) and the Energy and Fuel Management

8            Class falls within the Generation Function (Exhibit PJC-4). Within ESI’s

9            organizational structure, all of the Test Year expenses relating to the

10           Energy and Fuel Management Class of services relate to tasks performed

11           by the SPO organization. Furthermore, the SPO is the only organization

12           within ESI or Entergy that performs the services included in this class.

13

14   Q.      DO YOU SPONSOR ANY OF ETI’S NON-AFFILIATE COSTS?

15   A.      Not with respect to the Operations & Maintenance (“O&M”) services and

16           costs that I sponsor.          Those services, the personnel performing those

17           services, and the associated costs are entirely associated with ESI. ETI

18           does not provide or contract on its own for any of the services I describe;

19           rather, ETI and the other EOCs receive these services solely from ESI

20           and, more specifically, from the SPO organization. The capital costs that I

21           sponsor contain affiliate costs as well as non-affiliate costs, which the

22           SPO organization procures for ETI.




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     Entergy Texas, Inc.                                                                Page 38 of 75
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1    Q.      WILL YOU BE ADDRESSING THE COSTS OF THE FUEL, ENERGY

2            AND       CAPACITY             PRODUCTS       PROCURED        BY           THE    SPO

3            ORGANIZATION ON BEHALF OF ETI?

4    A.      No. My testimony addresses only the services provided by SPO for ETI

5            (and certain capital expenditures associated with those services), which

6            services, as described below, include the procurement of energy, fuel and

7            capacity     products      for   the   EOCs    (including   ETI);     however,      the

8            reasonableness of the costs for such energy, fuel and capacity products is

9            addressed by other witnesses.

10

11   Q.      PLEASE        EXPLAIN          HOW     THE   REMAINING      PARTS          OF    YOUR

12           TESTIMONY ADDRESSING AFFILIATE COSTS ARE ORGANIZED.

13   A.      Section III.A of my testimony provides a brief description of the SPO

14           organization. In Section III.B, I summarize the total O&M affiliate charges

15           for the Energy and Fuel Management Class. In Section III.C, I explain

16           why the costs in this class are necessary. Section III.D explains why

17           these affiliate costs are reasonable, why they meet the “not higher than”

18           standard, and why they represent the actual cost of providing these

19           services.     Section III.E addresses the Energy and Fuel Management-

20           related Capital Additions.




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     Entergy Texas, Inc.                                                         Page 39 of 75
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1                                   A.       The SPO Organization

2    Q.      WHERE DOES THE SPO FIT INTO ENTERGY’S UTILITY GROUP

3            OPERATIONS?

4    A.      System Planning & Operations is one of several operating departments

5            that compose the Utility Operations Group. During the Test Year, the

6            SPO, led by the Vice President, System Planning and Operations, was

7            staffed by 117 ESI employees who provided services to the EOCs.

8

9    Q.      PLEASE        PROVIDE          AN   OVERVIEW   OF      THE   PURPOSE       AND

10           ORGANIZATION OF THE SPO.

11   A.      All employees of the SPO organization, which provides the services

12           associated with the Energy and Fuel Management Class of services, are

13           employed to accomplish three distinct, but interrelated tasks.

14                   First, the SPO acquires fuel and fuel transportation services for the

15           EOCs’ fossil-fueled generating units. The SPO also procures wholesale

16           purchased power for the EOCs. The fuel purchasing task is one that any

17           utility which operates generating facilities must perform—someone must

18           negotiate for and buy fuel and then arrange for its delivery to the power

19           plants. The SPO performs that function for the Entergy System. Similarly,

20           every utility has the choice of generating power for itself or buying it from

21           others, and if the choice is to purchase power, someone must negotiate

22           the terms and conditions of power contracts and arrange for the delivery of

23           the purchased power. The SPO performs these functions as agent for the




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     Entergy Texas, Inc.                                                                  Page 40 of 75
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1             EOCs. Related to these very broad tasks are a variety of complex sub-

2             tasks such as selling excess power when available and ensuring that

3             invoices for power sales are issued and invoices for fuel and power

4             purchases are paid and that contract terms and conditions are fulfilled.

5             The SPO performs these tasks as well.

6                          Second, the SPO dispatches the generation in the Entergy Control
                      14
7             Area.          Every utility system is required by the North American Electric

8             Reliability Council (“NERC”) operating guidelines to either operate a

9             Control Area or make arrangements to be included in a Control Area or a

10            regional transmission organization.              The Entergy System currently

11            operates its own Control Area that consists of the service areas of all of

12            the EOCs.          The task of dispatching the generation (nuclear and non-

13            nuclear) within Entergy's Control Area is performed by the SPO.

14                         Third, the SPO plans for the future resource requirements of the

15            Entergy System, and manages the procurement of limited and long-term

16            resources pursuant to those plans.             Every utility must consider future

17            system requirements and determine the kinds of resources that it will need

18            in order to meet its prospective obligation to provide reliable and economic

19            power to its customers, and then must procure the supplemental

20            resources identified in the plan.             Additionally, regulators and other


     14
          The control area is defined to be the geographic area over which the responsible agent is
          required to match supply to total electric demand at every instant of time, within a tolerance
          set by the NERC.




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     Entergy Texas, Inc.                                                            Page 41 of 75
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1            governmental organizations frequently require electrical utility systems to

2            provide detailed information about their future plans.          Someone must

3            develop      and    implement   resource       plans   and   then     prepare   the

4            documentation, supporting studies and related regulatory filings that are

5            required. The SPO also performs these functions for the EOCs. All three

6            tasks are distinct, but highly interrelated.

7                    In order to accomplish these tasks, during the Test Year, the SPO

8            was divided into seven groups, which are indicated in the organizational

9            chart presented in Exhibit PJC-5. The individuals in charge of each of

10           these groups report directly to the Vice President in charge of the SPO.

11           The seven groups within the SPO, and a brief description of the services

12           performed by each, are:

13           (1)     Energy Management Organization (“EMO”), which is responsible

14                   for planning for and procurement of short-term fuel and purchased

15                   power resources to meet customers’ needs, and the dispatch of the

16                   entire Entergy Control Area generation fleet to provide reliable,

17                   economic electric service;

18           (2)     Asset Operations group, which is responsible for the procurement

19                   of limited- and long-term supply resources to meet the electric utility

20                   needs of the Entergy System and the              responsibility for coal

21                   commodity and transportation contracts for           the System’s coal

22                   plants;




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     Entergy Texas, Inc.                                                        Page 42 of 75
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1            (3)     Planning Analysis group, which is responsible for long-term

2                    planning and analysis in support of additional resources required to

3                    provide reliable and economic electric service to the EOCs’

4                    customers;

5            (4)     Regulatory Affairs and Energy Settlements group, which is

6                    responsible for providing business, compliance        and regulatory

7                    support services to the SPO, developing and managing SPO’s

8                    budget and cost control initiatives, ensuring that SPO’s activities

9                    are compliant with the Sarbanes-Oxley Act, and administering the

10                   Intra-System Bill associated with the Entergy System Agreement;

11           (5)     Project and Performance Management group, which is responsible

12                   for coordinating the development of SPO’s business plan and key

13                   performance        measures,   managing   the   Entergy    Continuous

14                   Improvement initiative for SPO, overseeing internal approval

15                   processes for major SPO projects, and performing special projects

16                   as needed;

17           (6)     Strategic Initiatives group, which is primarily responsible for

18                   activities associated with SPO’s evaluation of future operating

19                   environments, including the benefits of participating in an RTO and

20                   now, membership in and the transition of the Entergy System to

21                   MISO; and

22           (7)     Power Delivery and Technical Services group which is responsible

23                   for managing the SPO’s evaluation of transmission deliverability




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     Entergy Texas, Inc.                                                        Page 43 of 75
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1                    associated with existing or new generating facilities, and managing

2                    the SPO’s transmission service agreements.

3                    A more detailed description of the services provided by each of

4            these groups and their necessity to ETI’s responsibilities as a bundled

5            electric utility are further described below.

6

7              B.      Overview of Costs – Energy and Fuel Management Class

8    Q.      WHAT ARE THE TOTAL ETI ADJUSTED TEST YEAR CHARGES FOR

9            THE ENERGY AND FUEL MANAGEMENT CLASS THAT YOU

10           SPONSOR?

11   A.      As shown in Table 1 below, the total affiliate charges for the Energy and

12           Fuel Management Class that I sponsor are $3,742,314. The table shows

13           the following information:

14           Total Billings                 Dollar amount of total Test Year billings from
15                                          ESI to all Entergy companies, plus the dollar
16                                          amount of all other affiliate charges that
17                                          originated from any Entergy company. This is
18                                          the amount from Column (C) of the cost
19                                          exhibits PJC-A, PJC -B, and PJC -C.

20           Total ETI Adjusted             ETI’s adjusted amount for electric cost of
21                                          service after pro forma adjustments and
22                                          exclusions.

23           % Direct Billed                The percentage of the ETI adjusted Test Year
24                                          amount that was billed 100% to ETI.

25           % Allocated                    The percentage of the ETI adjusted Test Year
26                                          amount that was allocated to ETI.




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     Entergy Texas, Inc.                                                                   Page 44 of 75
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                       Table 1: Total ETI Affiliate Charges for the Energy and Fuel
                            Management Class for July 1, 2010-June 30, 2011

                                                                       Total ETI Adjusted
                                                                               %                %
                         Class                 Total        Amount        Direct Billed     Allocated
                                              Billings
             Energy and Fuel                $25,253,856   $3,742,314        8.70%            91.30%
             Management Class



1    Q.      WHAT ARE THE MAJOR COST COMPONENTS OF THE CHARGES

2            FOR THE ENERGY AND FUEL MANAGEMENT CLASS?

3    A.      The major cost components are reflected in Table 2 below.

               Table 2: Major Components of ETI Affiliate Charges for the Energy
                   and Fuel Management Class for July 1, 2010-June 30, 2011

                           Cost Component                   Total ETI       % of Total
                                                            Adjusted
                     Payroll and Employee Benefits         $2,901,624          77.5%
                     Outside Services                        $300,650           8.0%
                     Office & Employee Expenses              $286,221           7.6%
                     Service Company Recipient               $254,236           6.8%
                     Other                                     $(417)           0.0%
                     Total                                 $3,742,314          100%


4    Q.      WHAT IS THE PURPOSE OF THIS TABLE AND ITS COST

5            CATEGORIES?

6    A.      I directly sponsor the costs shown in this table because they comprise the

7            Total ETI Adjusted amount for the Energy and Fuel Management Class for

8            the Test Year. This breakout of costs provides an additional “view” of the

9            components of this class. I also identify other witnesses in this case who

10           also support these costs because they address the corporate structures




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     Entergy Texas, Inc.                                                       Page 45 of 75
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1            and practices that underlie these costs.          For example, the table

2            demonstrates that 77.5% of the costs in the Energy and Fuel Management

3            Class are labor-related costs (Payroll and Employee Benefits). Company

4            witness Kevin G. Gardner discusses ESI’s overall payroll and benefits-

5            related structure and practices. “Outside Services” reflect the services

6            provided by non-Entergy employees and firms, such as the independent

7            monitors overseeing resource procurement processes.               “Office and

8            Employee Expenses” includes: office and general expenses (e.g., paper,

9            postage, and other general office expenses); employee expenses (e.g.,

10           car mileage, local travel expenses, training and business travel airfare);

11           moving and relocation expenses (e.g., costs to relocate new and/or

12           existing employees to new job locations); telecommunications expenses

13           (e.g., long distance telephone charges, conference calls, and cellular

14           phone expenses); and rent expenses for ETI. These types of costs are

15           addressed in more detail by Company witness Thomas C. Plauché.

16           Finally, the costs for “Service Company Recipient,” which are services that

17           ESI provides to itself, are in turn spread to all affiliates that receive ESI

18           services.      Company witness Stephanie B. Tumminello explains this

19           service company recipient process.        Other miscellaneous costs and

20           credits are included in the “Other” cost components.          My testimony

21           addresses the necessity and reasonableness of the amounts for these

22           costs.




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     Entergy Texas, Inc.                                                        Page 46 of 75
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1    Q.      PLEASE        DESCRIBE         THE   EXHIBITS     THAT     SUPPORT        THE

2            INFORMATION INCLUDED IN TABLE 1 HEREIN.

3    A.      Attached to my direct testimony are exhibits showing the calculation of the

4            Total ETI Adjusted amount for the Energy and Fuel Management Class.

5            In Exhibit PJC-A, the information is shown broken down by the

6            departments comprising the class.          Exhibit PJC-B shows the same

7            information broken down by project code and by the billing method

8            assigned to each project code. Exhibit PJC-C shows the information by

9            class, department and project code. For each exhibit, the amounts in the

10           columns represent the following information:

             Column (A) –                     Dollar amount of total Test Year billings and
             Support                          charges from ESI to all Entergy Business
                                              Units, plus the dollar amount of all other
                                              affiliate charges to ETI that originated from
                                              any Entergy Business Unit.
             Column (B) –                     Dollar amount that was included in the
             Service Company                  service company recipient allocation.
             Recipient                        Service company recipient charges are the
                                              cost of services that ESI provides to itself,
                                              which in turn are charged to affiliates that
                                              receive those services.         The service
                                              company recipient allocation process is
                                              described in the testimony of Company
                                              witness Tumminello.
             Column (C) –                     Represents the sum of Columns (A) and (B).
             Total
             Column (D) –                     That portion of Column (C) that was billed
             All Other Business Units         and charged to Business Units other than
                                              ETI.

             Column (E) –                     Represents the difference between Columns
             ETI Per Books                    (C) and (D).




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     Entergy Texas, Inc.                                                      Page 47 of 75
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             Column (F) –                   Represents amounts that are excluded from
             Exclusions                     ETI electric cost of service. The exclusions
                                            are described in the testimony of Company
                                            witness Tumminello.

             Column (G) –                   Pro Forma Amounts include adjustments for
             Pro Forma Amount               known and measurable changes, and
                                            corrections.

             Column (H) –                   ETI adjusted amount requested for recovery
             Total ETI Adjusted             in this case for this class (Column (E) plus
                                            Columns (F) and (G)).

1            In her direct testimony, Ms. Tumminello describes the calculations that

2            take the dollars of support services in Column (E) to the Total ETI

3            Adjusted Numbers shown in Column (H).

4

5    Q.      PLEASE DESCRIBE THE “EXCLUSIONS” COLUMN SHOWN IN YOUR

6            EXHIBITS PJC -A, PJC -B, and PJC -C.

7    A.      This column includes items charged to capital accounts, below the line

8            accounts and other balance sheet accounts. These excluded amounts

9            are discussed in the direct testimony of Company witness Tumminello.

10

11   Q.      ARE THERE ANY PRO FORMA ADJUSTMENTS APPLICABLE TO THIS

12           AFFILIATE CLASS?

13   A.      Yes.      Pro Formas and their sponsoring witnesses are shown in

14           Exhibit PJC-D.




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     Entergy Texas, Inc.                                                      Page 48 of 75
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1    Q.      PLEASE DESCRIBE THE TYPES OF SERVICES PROVIDED BY THE

2            SPO AND INCLUDED IN THE ENERGY AND FUEL MANAGEMENT

3            CLASS OF SERVICES.

4    A.      Generally, the SPO provides services related to making, accounting for,

5            and defending decisions regarding the procurement of new generation,

6            decisions regarding which System generating units are to be committed

7            and operated, how those units are operated, and how much wholesale

8            energy and fuel is purchased.

9                    As previously discussed, seven major groups comprise the SPO:

10           EMO; Asset Operations; Planning Analysis; Regulatory Affairs and Energy

11           Settlements; Power Delivery and Technical Services; Project and

12           Performance Management; and Strategic Initiatives.

13

14                                   C.     Necessity of Services

15   Q.      WHAT DOES THE EMO DO?

16   A.      The EMO is responsible for planning for and procuring short-term

17           resources to meet customers’ needs, and the dispatch of the entire

18           Entergy Control Area generation fleet to provide reliable, economic electric

19           service. The EMO includes the following major sections and functions:

20                  The Operations Planning section, which is responsible for the

21                   development of monthly, weekly and daily energy plans, as well as

22                   the development of generating unit commitment plans, and




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     Entergy Texas, Inc.                                                       Page 49 of 75
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1                    maintenance schedules, to ensure that reliable and economic

2                    supplies of energy are available to the System on a daily basis.

3                   The Gas, Oil, and Wholesale Power sections, which deal with gas

4                    and oil procurement and ensures that the utility’s gas and fuel oil

5                    supply and transportation agreements are administered in an

6                    effective and efficient manner. This section purchases natural gas

7                    and fuel oil for delivery to the Entergy System's generating plants

8                    that consume natural gas and/or fuel oil. During the Test Year, the

9                    Gas and Oil Supply section procured 151.3 million MMBtus of
                                                             15
10                   natural gas for ETI’s generating plants.

11                            The Wholesale Power section also continuously monitors

12                   bulk power markets in order to purchase short term energy when

13                   such power is available at a lower cost than the cost of self-

14                   generation and to seek opportunities to sell energy off-system for

15                   all time periods other than the current 24 hours, which is the

16                   responsibility of the Generation Dispatch and Current Day

17                   Marketing function.    During the Test Year, the Power Marketing

18                   section supported the procurement of over 27.7 million MWh of
                                                        16
19                   wholesale power on behalf of ETI.




     15
          See Schedule I-16.1.
     16
          See Schedule H-12.4a-g.




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     Entergy Texas, Inc.                                                         Page 50 of 75
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1                   The Power Transactions & Dispatch section, which is responsible

2                    for meeting projected electric demand reliably and at the lowest

3                    reasonable cost.       Specifically, this section dispatches available

4                    generation capacity and other resources to meet the Entergy

5                    System’s real-time electric demand.           This section is also

6                    responsible for marketing of excess generation and purchasing

7                    additional resources on a real-time basis.

8                             During the Test Year, the Power Transactions & Dispatch

9                    section was responsible for the commitment and dispatch of

10                   approximately 3,500 MW of ETI-owned or ETI-allocated capacity on

11                   a coordinated basis with the capacity owned by the other EOCs.

12                  The Operations Support section, which provides support of various

13                   planning and regulatory issues that affect real-time dispatch

14                   and operations.

15

16   Q.      ARE THE SERVICES PROVIDED BY THE EMO NECESSARY?

17   A.      Yes. It is common practice for those utilities that operate a Control Area

18           or procure electric energy from wholesale resources to employ a short

19           term planning function, a dispatch function and a power marketing function

20           in order to achieve the goal of meeting such utility’s projected electric

21           demand reliably and at the lowest reasonable cost. Furthermore, it is also

22           common practice for those utilities that operate gas- and oil-fired power

23           plants to have a gas and oil supply function in order to meet their




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     Entergy Texas, Inc.                                                         Page 51 of 75
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1            projected gas and oil demand and to ensure that such utility’s gas and fuel

2            oil supply and transportation agreements are administered in an effective

3            and efficient manner.

4

5    Q.      WHAT DOES THE ASSET OPERATIONS GROUP DO?

6    A.      This group is responsible for the procurement of limited- and long-term

7            fuel and generation resources to meet the electric utility needs of the

8            Entergy System. The Asset Operations group is responsible for the formal

9            Requests for Proposals (“RFP”) process by which the Entergy System

10           solicits proposals for purchased power agreements or acquires new or

11           existing power plants.         This group also negotiates bi-lateral purchased

12           power agreements when such opportunities arise. Finally, the group also

13           has the responsibility for dealing with issues under the fuel provisions of

14           the Joint Ownership and Operating Agreement governing the Big Cajun II,

15           Unit 3 generating unit.

16                   During the Test Year, the Asset Operations group was responsible

17           for executed agreements procuring 660 MW of limited- and long-term

18           wholesale power which was allocated either in whole or in part to ETI.

19           Additionally, the Asset Operations group was also responsible for

20           significant activity outside of the Test Year that affected power purchases

21           during the Test Year, as discussed in the testimony of Company witness

22           Robert R. Cooper.




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     Entergy Texas, Inc.                                                           Page 52 of 75
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1                    The     Asset     Operations   group   is   also   responsible    for   the

2            procurement of coal for the EOCs’ coal-fired power plants, administering

3            coal supply contracts and managing the maintenance of the rail car fleet

4            leased by EGSL and EAI, including the transportation of coal to the Roy S.

5            Nelson Power Plant near Lake Charles, Louisiana (in which ETI is a co-

6            owner), and to the two other coal-fired power plants on the System – the

7            Independence Steam Electric Station and the White Bluff Steam Electric

8            Station in Arkansas.

9                    During the Test Year, this group procured the coal supply and

10           arranged the transportation of approximately 2.4 million tons of coal that

11           were delivered to the Roy S. Nelson plant. Comparably, it also received

12           approximately 1.0 million tons of coal during the Test Year for ETI and

13           EGSL’s share of the output of Big Cajun II, Unit 3.

14

15   Q.      ARE THESE SERVICES NECESSARY?

16   A.      Yes. Integrated utilities procure limited- and long-term resources to meet

17           the electric utility needs of their customers.       It is common practice for

18           utilities to utilize a competitive solicitation process when procuring

19           purchased power or acquiring new or existing power plants to facilitate the

20           utility’s procurement of the resource at a reasonable price.             It is also

21           common practice for those utilities that operate coal-fired power plants to

22           have a coal supply function in order to meet their projected coal demand

23           and to ensure that such utility’s coal supply, railcar maintenance, and coal




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     Entergy Texas, Inc.                                                            Page 53 of 75
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1            transportation agreements are administered in an effective and efficient

2            manner.

3

4    Q.      WHAT DOES THE PLANNING ANALYSIS GROUP DO?

5    A.      The Planning Analysis group is responsible for planning for the long-term

6            resource requirements necessary to provide reliable and economic electric

7            service to the EOCs’ customers.            That group ensures that the utility’s

8            generation and wholesale transactions resources are planned pursuant to

9            consistent and accepted planning criteria.           Specifically, this group is

10           responsible for the development of long-term Strategic Resource Plans,

11           which result in the matching of the Entergy System’s long-term projected

12           load and resources.            In addition to the analysis of potential resource

13           acquisitions, the Planning Analysis group performs long-term fuels

14           planning      and     analysis,     peak   load   forecasting   and     production

15           cost forecasting.

16                   During the Test Year, the Planning Analysis group developed

17           capacity and energy plans that support ETI’s objective to achieve the

18           lowest reasonable energy costs for its customers consistent with the

19           Entergy System Agreement and known and reasonably anticipated

20           System conditions.




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     Entergy Texas, Inc.                                                       Page 54 of 75
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1    Q.      ARE THE SERVICES PROVIDED BY THE PLANNING ANALYSIS

2            GROUP NECESSARY?

3    A.      Yes. It is common practice for those utilities that have an obligation to

4            provide reliable generation supplies to customers to employ a long-term

5            planning and analysis function in order to achieve the goal of meeting

6            such utility’s projected electric demand at a reasonable cost and to ensure

7            that such utility’s generation and wholesale transactions resources are

8            planned pursuant to consistent and accepted planning criteria.

9

10   Q.      WHAT        DOES       THE     REGULATORY     AFFAIRS     AND       ENERGY

11           SETTLEMENTS GROUP DO?

12   A.      The Regulatory Affairs and Energy Settlements group is responsible for

13           providing business and regulatory support services to the SPO, and, in

14           turn, for the EOCs. These services include bulk power energy accounting,

15           administering the Intra-System Bill associated with the Entergy System

16           Agreement and the administration and accounting related to wholesale

17           energy and fuel invoices.

18                   During the Test Year, fuel and electricity-related invoices totaling

19           approximately $2.7 billion, were verified and processed by the Energy

20           Analysis and Reporting section to ensure proper payment and/or billing.

21           The group prepared numerous reports required by federal and state

22           administrative agencies and assisted in the preparation of monthly

23           estimated and actual accounting entries for ETI. These services provide




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     Entergy Texas, Inc.                                                          Page 55 of 75
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1            benefits to ETI’s customers by providing to internal and external groups

2            accurate and timely fuel and energy data and invoice processing in a cost

3            effective manner.

4                    The Regulatory Affairs and Energy Settlements group also supports

5            the filing requirements of various state and federal regulators, develops

6            and manages SPO’s budget, including the monitoring of related activities

7            and costs, and identifies and implements cost control initiatives. Lastly,

8            the Regulatory Affairs and Energy Settlements group monitors compliance

9            with the electric reliability standards for SPO and ensures that SPO’s

10           activities are compliant with the Sarbanes-Oxley Act.

11

12   Q.      ARE THE SERVICES PROVIDED BY THE REGULATORY AFFAIRS

13           AND ENERGY SETTLEMENTS GROUP NECESSARY?

14   A.      Yes. It is common practice for those utilities that operate power plants,

15           buy and sell electricity, and operate in a multi-jurisdictional and multi-utility

16           environment as part of a larger combined system concept, to maintain an

17           organization to provide: (1) business and regulatory support services;

18           (2) bulk power energy accounting; (3) administration of billing associated

19           with the combined system; (4) administration and accounting related to

20           wholesale energy and fuel invoices, for the purpose of enhancing the

21           efficiency and effectiveness of the other fuel, energy and dispatch

22           related functions and (5) a compliance function to ensure compliance with

23           the electric reliability standards.




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     Entergy Texas, Inc.                                                       Page 56 of 75
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1                    As part of the overall management of SPO’s fuel and energy

2            management activities the budgeting and cost control measures provided

3            by the SPO Regulatory Affairs and Settlements group helps ensure the

4            reasonableness and necessity of the costs incurred and that such

5            expenditures are managed within the approved budget.

6

7    Q.      WHAT DOES THE PROJECT AND PERFORMANCE MANAGEMENT

8            GROUP DO?

9    A.      The Project and Performance Management group is responsible for

10                  coordination of the development of SPO’s business plan and key

11                   performance measures; and

12                  oversight of the internal approval processes for major SPO projects

13                   and performing special projects as needed.

14           This group is also responsible for overseeing the Entergy Continuous

15           Improvement (“ECI”) initiative for SPO that I discuss later in my testimony.

16

17   Q.      ARE THESE SERVICES NECESSARY?

18   A.      Yes. The efficient and cost effective performance of the necessary fuel

19           and energy management activities enumerated earlier in my testimony

20           requires attention to the performance measures provided by the SPO

21           Project and Performance Management group.




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     Entergy Texas, Inc.                                                     Page 57 of 75
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1    Q.      WHAT DOES THE STRATEGIC INITIATIVES GROUP DO?

2    A.      This group was formed for the purpose of focusing on and supporting

3            several key initiatives facing the regulated Operating Companies, primarily

4            the activities related to the evaluation of future operating environments,

5            including the benefits of participating in an RTO, and now, membership in

6            and the transition of the Entergy System to MISO.

7

8    Q.      ARE THESE SERVICES NECESSARY?

9    A.      Yes. The System’s decision to join an RTO – specifically, MISO – has

10           far-reaching implications for how the Operating Companies will plan and

11           operate their generation systems.      The Strategic Initiatives group is

12           responsible for evaluating issues and situations that will affect future

13           operations, and the Strategic Initiatives group will play a key role in

14           ensuring ETI’s future operations are consistent with reliable and economic

15           service.

16

17   Q.      WHAT DOES THE POWER DELIVERY AND TECHNICAL SERVICES

18           DO?

19   A.      The Power Delivery and Technical Services group is responsible for

20           managing the SPO’s evaluation of transmission deliverability associated

21           with existing or new generating facilities, and managing the SPO’s

22           transmission service agreements.




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     2011 Rate Case


1    Q.      ARE THESE SERVICES NECESSARY?

2    A.      Yes. The separation of the merchant and transmission functions directed

3            by the FERC requires that the SPO have the ability to study and manage

4            transmission service associated with the System’s existing and proposed

5            generating resources.

6

7             D.      Reasonableness of Energy and Fuel Management Charges

8    Q.      PLEASE DESCRIBE THE STAFFING LEVELS ASSOCIATED WITH THE

9            ENERGY AND FUEL MANAGEMENT CLASS OVER THE PERIOD 2008

10           THROUGH THE TEST YEAR.

11   A.      SPO’s staffing levels for 2008, 2009. 2010 and the Test Year is reflected

12           in Table 3 below. The increase in Test Year staffing levels over 2008 and

13           2009 is consistent with the addition of the new Strategic Initiatives group

14           as well as the addition of a dispatcher position in the EMO group, required

15           by an increased workload in the Power Transactions and Dispatch

16           section.

                                            Table 3: SPO Headcount

                     2008                    2009           2010        Test Year

                     110                     115             116             118




2011 ETI Rate Case                                                    9-61
     Entergy Texas, Inc.                                                           Page 59 of 75
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     2011 Rate Case


1    Q.      HAS SPO PERFORMED ANY BENCHMARKING TO SUPPORT THE

2            REASONABLENESS OF ITS COSTS?

3    A.      No, but as discussed by Company witness Jeanne F. Kenney, the

4            Company has provided benchmarking analysis of both non-production

5            O&M costs, including A&G costs, which include SPO costs. This high

6            level view further supports the reasonableness of costs in the Energy and

7            Fuel Management Class.

8

9    Q.      WHAT WERE THE ACTUAL COST TRENDS FOR THE ENERGY AND

10           FUEL MANAGEMENT CLASS FOR THE LAST THREE YEARS AS

11           COMPARED TO THE TEST YEAR?

12   A.      Table 4 below presents the total affiliate O&M costs for the class as a

13           whole for the last three years and the Test Year.

                  Table 4: ESI Energy and Fuel Management Cost Trends

                       2008                 2009           2010        Test Year

                     $3,072,925       $3,527,979         $3,140,089    $3,736,054



14   Q.      DO THE FIGURES IN THIS COST TREND TABLE INCLUDE ALL

15           COSTS        INCURRED          BY     ESI   FOR   THE    ENERGY       AND   FUEL

16           MANAGEMENT CLASS DURING THE LISTED PERIODS?

17   A.      No. The ESI O&M cost trend figures have been adjusted primarily to

18           exclude certain costs incurred by ESI to support efforts to spin off




2011 ETI Rate Case                                                          9-62
     Entergy Texas, Inc.                                                          Page 60 of 75
     Direct Testimony of Patrick J. Cicio
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1            Entergy's non-regulated nuclear operations because such costs are not

2            representative of ESI's ongoing cost of supporting ETI utility service.

3            Company witness Tumminello provides further explanation regarding the

4            adjustments to the cost trend data in her direct testimony.

5

6    Q.      WHAT DO THESE COST TRENDS REFLECT?

7    A.      These cost trends reflect a reasonable increase in overall costs for the

8            class from 2008 through the Test Year. The increase in Test Year costs

9            over previous annual periods largely reflects new or increased costs

10           associated with: (1) the new Strategic Initiatives group, including the

11           addition of a new Vice President position to lead that group; (2) the

12           considerable increase in compliance activity—required by federal law—for

13           which SPO is responsible; and (3) the addition of a dispatcher position

14           addressed above. In summary, Table 4 reflects a reasonable increase in

15           SPO costs over recent years and a reasonable level of costs in the Test

16           Year.

17

18   Q.      PLEASE DESCRIBE THE WORKLOAD FACED BY THE SPO.

19   A.      SPO workload continues to increase significantly and is appropriate to

20           consider when evaluating the reasonableness of its overall costs. Efforts

21           continue with respect to the transformation of the EOCs’ generation

22           portfolios and the procurement of additional resources. Since the last rate

23           case, SPO has initiated and completed, or is in the process of conducting,




2011 ETI Rate Case                                                         9-63
     Entergy Texas, Inc.                                                          Page 61 of 75
     Direct Testimony of Patrick J. Cicio
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1            three RFPs—the Summer 2009 RFP, the 2010 Renewable RFP and,

2            more recently, the ongoing 2011 Western Region RFP, which seeks a

3            resource for 2017, already pre-allocated to ETI by the Entergy Operating

4            Committee. Further, the Planning Analysis group currently forecasts the

5            need to obtain even additional resources to serve the Western Region in

6            2020. Moreover, additional complexities continue to be added to SPO’s

7            functions due to the planned exit of EAI and EMI from the System

8            Agreement, effective 2013 and 2015, and the recent announcement that

9            the Entergy System will join MISO. Both of these future events require

10           SPO’s planning teams to consider and plan for a wider array of possible

11           outcomes while the overall SPO organization prepares to incorporate new

12           structures and processes.        Finally, as is the case with other similarly

13           situated utilities, SPO continues to face and respond to increases in

14           regulatory     compliance      requirements    and   significant     changes     in

15           environmental laws and regulations.           This increasing workload further

16           supports the reasonableness of costs in this class.

17

18   Q.      DOES THE SPO HAVE IN PLACE A BUDGETING PROCESS TO

19           CONTROL COSTS?

20   A.      Yes. The SPO undergoes an extensive annual budget preparation and

21           review process. Within this process, a proposed budget is finalized for the

22           following year. As an input to the budget, the SPO is allocated a certain

23           percentage increase in wages for the organization’s employees.                 This




2011 ETI Rate Case                                                         9-64
     Entergy Texas, Inc.                                                        Page 62 of 75
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1            allows for the flexibility to reward individual performance in any given year,

2            but also ensures that total labor costs continue to track labor market

3            conditions. Further, non-labor costs are reviewed for necessity and cost

4            effectiveness.      Annual budgets are prepared within SPO, approved by

5            SPO executive management, corporate management and, ultimately, the

6            board of directors of Entergy Corporation.

7

8    Q.      IS COMPLIANCE WITH THE BUDGET MONITORED?

9    A.      Yes. SPO management continually monitors incurred expenses against

10           budget, and frequently approves expenses prior to expenses being

11           incurred.     For example, the SPO management generally pre-approves

12           employee training (e.g., seminars, travel) prior to an employee’s

13           registration for such training. Likewise, most employee business travel is

14           also discussed and approved by SPO management prior to travel costs

15           being incurred. Additionally, on a monthly basis, the SPO expenditures

16           are reviewed by executive management to ensure that they are on track

17           with the annual budget. To the extent that there are deviations within the

18           budget year, discretionary projects may either be advanced or postponed,

19           with the approval of the SPO executive management, to ensure that the

20           SPO expenditures are reasonable.




2011 ETI Rate Case                                                       9-65
     Entergy Texas, Inc.                                                               Page 63 of 75
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1    Q.      ARE SPO EMPLOYEES HELD ACCOUNTABLE FOR DEVIATIONS

2            FROM BUDGET?

3    A.      Most employee expenses are pre-approved by the appropriate level of

4            SPO management.                Any significant unbudgeted cost must be pre-

5            approved by the Vice President, System Planning and Operations.

6            Adherence to budget is a priority for all SPO staff.              Compliance with

7            approved budgets is also included in the performance goals of the

8            employees.

9

10   Q.      HAS SPO UNDERTAKEN OTHER MEASURES OR INITIATIVES TO

11           ENSURE THAT ITS COSTS ARE REASONABLE?

12   A.      SPO, on an ongoing basis, actively seeks to discover new ways to

13           improve      processes         within   the   organization   through     the   Entergy

14           Continuous Improvement (“ECI”) initiative, a process which also is

15           overseen by the Project and Performance Management group and which

16           encourages employees to seek out areas where practices, processes and

17           procedures related to their organizations can be improved upon to

18           enhance effectiveness and efficiency. Improvements identified through

19           the ECI process often result in reduced costs. During the Test Year, SPO,

20           given its focus on buying both fuel and power for the EOCs, was

21           successful in discovering and implementing a number of improvements

22           that resulted in fuel and purchased power cost reductions, as presented in

23           Schedule I-21. SPO also streamlined and automated a number of regular




2011 ETI Rate Case                                                             9-66
     Entergy Texas, Inc.                                                         Page 64 of 75
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1            work processes, allowing labor redeployment and reducing or delaying the

2            need to increase O&M expenses to keep up with the increasingly

3            demanding workload that I discussed earlier in my testimony.

4

5                    E.      Billing of Energy and Fuel Management Charges

6    Q.      HOW ARE SPO’S COSTS BILLED TO ETI?

7    A.      Please refer to Exhibits PJC-B and PJC-C. These exhibits show all the

8            costs included in the Energy and Fuel Management Class by project code

9            and reflect the ESI billing method assigned to each project code.

10                   The affiliate billing process is explained by Company witness

11           Tumminello. Where appropriate, costs are billed directly to ETI and other

12           affiliates. Costs that are billed directly to ETI reflect the fact that certain

13           Energy and Fuel Management Class activities are for the specific benefit

14           of ETI. Only when incurred costs benefit more than one of the EOCs are

15           such costs billed through an allocation. With respect to the Energy and

16           Fuel Management Class, some costs are billed to ETI through an

17           allocation, which reflects the fact that more than one of the EOCs

18           benefited from the services delivered. Therefore, ESI costs are billed to

19           ETI both directly and through various allocation methods.




2011 ETI Rate Case                                                        9-67
     Entergy Texas, Inc.                                                      Page 65 of 75
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1    Q.      ON WHAT BASIS ARE COSTS OF THESE ENERGY AND FUEL

2            MANAGEMENT SERVICES BILLED?

3    A.      Each ESI affiliate class of service, including the Energy and Fuel

4            Management Class, comprises one or more project codes. As Company

5            witness Tumminello explains, only one billing method is assigned to each

6            project code.      Several organizations may bill to a single project code.

7            However, the billing method for each project code remains the same,

8            regardless of which organization charges to that project code. A billing

9            method is selected based on cost causation. This procedure ensures that

10           the price charged to ETI for the services is no higher than the price

11           charged to other affiliates for the same or similar services, and represents

12           the actual cost of the services.

13

14   Q.      PLEASE EXPLAIN WHAT IS REFERRED TO BY COSTS BEING

15           “BILLED DIRECTLY” OR “ALLOCATED?”

16   A.      Affiliate charges are incurred by ETI when ESI employees or employees of

17           other affiliate companies provide services to ETI.       Affiliate costs are

18           charged to ETI through one of two methods. The costs are either billed

19           directly to ETI or the costs are allocated to ETI based on the primary cost

20           driver of the activity or project. The SPO function has consolidated, on a

21           system-wide basis, those activities that are common to all EOCs for which

22           scale and scope efficiencies can be realized. I will use the example of

23           Planning Analysis to explain whether an ESI charge will be billed directly




2011 ETI Rate Case                                                     9-68
     Entergy Texas, Inc.                                                         Page 66 of 75
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     2011 Rate Case


1            to ETI or allocated to ETI. If a Planning Analysis employee is working on

2            a specific ETI project, such as a Texas fuel reconciliation, then ETI is the

3            only EOC that benefits from this regulatory activity and all of the resulting

4            costs will be billed directly to ETI.     Conversely, if the same Planning

5            Analysis employee was working on the Strategic Resource Plan for the

6            Entergy System, all EOCs would benefit and the resulting costs would be

7            allocated based on the primary cost driver – in this case, the load

8            responsibility ratio. These rules apply to all of the work performed by

9            SPO employees.

10

11   Q.      HOW DID SPO DETERMINE WHICH ENTITY SHOULD BE BILLED?

12   A.      As a necessary part of accurately apportioning costs to the various

13           Entergy affiliates, a billing method is assigned to each project code that

14           first identifies the entities to which the cost is to be apportioned. When a

15           project code is established, a billing method is selected by SPO based on

16           the factors driving SPO to incur the expense; these factors are frequently

17           referred to as “cost drivers.” The billing method that is initially assigned by

18           the staff member is reviewed for appropriateness by SPO management.

19           In addition, billing methods assigned to project codes also are reviewed

20           periodically     by    budget   coordinators   and   SPO   management         for

21           appropriateness.       Each SPO project code has only one billing method

22           assigned to it and the billing method is selected to ensure that every

23           affiliate receiving service receives the appropriate allocation. Therefore,




2011 ETI Rate Case                                                        9-69
     Entergy Texas, Inc.                                                       Page 67 of 75
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1            the costs of all services performed under a project code are allocated

2            among the EOCs using the same criteria, at cost without profit or markup.

3            The use of a single billing method for each project code ensures that all

4            EOCs causing costs to be incurred and benefiting from the service pay an

5            appropriate proportion of the costs. It also ensures that the EOCs are, in

6            total, charged no more and no less than one hundred percent of the costs

7            for services provided under the project code. Finally, the use of a single

8            billing method, which is assigned based on cost causation principles,

9            ensures that each EOC is paying the same price for the same service,

10           and, that the prices charged to ETI are no higher than the prices charged

11           by ESI to the other EOCs for similar services.

12

13   Q.      PLEASE        DESCRIBE         THE   PREDOMINANT      BILLING     METHODS

14           EMPLOYED IN THE ENERGY AND FUEL MANAGEMENT CLASS OF

15           SERVICES.

16   A.      The predominant billing methods for the Energy and Fuel Management

17           Class are “LOADOPCO” (Responsibility Ratio), “DIRECTTX” (100% to

18           ETI), and “CAPXCOPC” (System Capacity without Coal). These three

19           billing methods make up 94.49% of the billings to ETI for the Energy and

20           Fuel Management Class. “LOADOPCO” makes up 81.12%; “DIRECTTX”

21           makes up 8.70%; and “CAPXCOPC” makes up 4.67%. Of these three

22           billing methods, “LOADOPCO” and “CAPXCOPC” allocate (rather than

23           direct bill) costs to ETI through the allocation method.




2011 ETI Rate Case                                                      9-70
     Entergy Texas, Inc.                                                                  Page 68 of 75
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1    Q.       WHY IS BILLING METHOD “LOADOPCO”                             APPROPRIATE           FOR

2             CERTAIN        ENERGY          AND      FUEL       MANAGEMENT               EXPENSES

3             ALLOCATED TO ETI?

4    A.       The majority of SPO services relate to the procurement, planning,

5             commitment, and dispatch of the Entergy System’s generating resources

6             and its wholesale power transactions. The need for SPO’s services is

7             driven by the necessity to obtain resources for the Entergy System as a

8             whole and each EOC’s need for such services is a part of and relative to

9             the Entergy System’s need for such services. Accordingly, for the majority

10            of SPO’s services, it is appropriate to apportion the corresponding cost in

11            a manner that relates the need of the EOC for resources to the need of

12            the Entergy System as a whole. “LOADOPCO,” which is based upon the

13            Responsibility Ratio (the ratio of each EOC’s load at the time of the
                                                                                                     17
14            Entergy System peak load to the Entergy System’s peak load),

15            accomplishes this.       For instance, Project Code F3PCW15830 captures

16            cost associated with planning activities performed for the Entergy System

17            and the EOCs. Associated costs are driven by the load responsibility

18            ration of each of the System’s generating plants.                           Accordingly,

19            “LOADOPCO,” which apportions cost based on load responsibility ratio, is

20            an appropriate billing method for this type of project.



     17
          Responsibility Ratio is a defined allocator in the Entergy System Agreement.




2011 ETI Rate Case                                                                 9-71
     Entergy Texas, Inc.                                                                 Page 69 of 75
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1    Q.      WHY IS BILLING METHOD “DIRECTTX” APPROPRIATE FOR THE

2            ENERGY AND FUEL MANAGEMENT EXPENSES ALLOCATED TO ETI?

3    A.      “DIRECTTX” bills cost 100% to ETI and is appropriate when the services

4            performed relate directly to and benefit only ETI. For example, Project

5            Code F3PPWET306 captures costs associated with the 2011 Western

6            Region RFP as part of the resource planning process for ETI.                        The

7            associated costs are caused by and are directly related to ETI, and are

8            therefore assigned to ETI, pursuant to billing method DIRECTTX.

9

10   Q.      WHY      IS    BILLING         METHOD      “CAPXCOPC”            APPROPRIATE        FOR

11           CERTAIN         ENERGY           AND      FUEL         MANAGEMENT           EXPENSES

12           ALLOCATED TO ETI?

13   A.      “CAPXCOPC” is based on the power level, in kilowatts, that could be

14           achieved if all non-coal and non-nuclear generating units were operating

15           at maximum capability simultaneously. It is appropriate to use this billing

16           method when the cost for SPO services relate to an EOC’s ownership of

17           non-coal and non-nuclear generation.                   For instance, Project Code

18           F3PCW18100 captures costs associated with payroll and office expenses

19           incurred in the planning and purchase of gas and oil for operating the

20           System’s natural gas and oil-fired power plants.                         Billing Method

21           “CAPXCOPC”          was        selected   for   this   project    code    because    the

22           corresponding costs related to SPO’s services under this project are

23           driven by the amount of natural gas and oil capacity owned by an EOC.




2011 ETI Rate Case                                                                9-72
     Entergy Texas, Inc.                                                         Page 70 of 75
     Direct Testimony of Patrick J. Cicio
     2011 Rate Case


1    Q.      YOU HAVE ADDRESSED THE DIRECT COSTS AND ALLOCATED

2            COSTS USED TO BILL 94.49% OF THE TOTAL ETI ADJUSTED

3            AMOUNT          ASSOCIATED       WITH      THE     ENERGY        AND       FUEL

4            MANAGEMENT CLASS.               WHY HAVE YOU NOT SPECIFICALLY

5            ADDRESSED THE REMAINING 5.51% OF THE COSTS OF THIS

6            CLASS?

7    A.      The remaining costs are billed through a number of other project codes

8            and billing methods. Given the number of billing methods, project codes

9            and relative dollar amounts, I have not gone into detail in this discussion in

10           an effort to keep the discussion at a manageable level. However, the

11           project codes and billing methods used to bill the remaining 5.51% of the

12           costs in this class are provided in my Exhibits PJC-B and PJC-C.               A

13           reader may reference these exhibits and then refer to the specific project

14           code summary contained in exhibits to the testimony of Company witness

15           Tumminello for a discussion of the particular billing method used and the

16           cost drivers for the activities captured in the particular project code.

17

18   Q.      HAVE YOU DETERMINED THAT THE COSTS REFLECTED IN THE

19           REMAINING 5.51% OF COSTS ASSOCIATED WITH THIS CLASS HAVE

20           BEEN BILLED APPROPRIATELY?

21   A.      Yes, I have reviewed each of the project codes and the associated billing

22           methods used to bill the remaining 5.51% of the costs of this class. The

23           cost drivers reflected in the billing method used to bill the costs of each




2011 ETI Rate Case                                                        9-73
     Entergy Texas, Inc.                                                        Page 71 of 75
     Direct Testimony of Patrick J. Cicio
     2011 Rate Case


1            project code are consistent with and reflect the cost drivers of the services

2            captured in each respective project code. Therefore, the costs billed to

3            ETI reasonably reflect the costs of the services received by ETI and are

4            no higher than the costs charged to other EOCs for the same or similar

5            types of services.

6

7    Q.      DO ANY OTHER ENTITIES DUPLICATE THE ENERGY AND FUEL

8            MANAGEMENT CLASS OF SERVICES?

9    A.      No. The SPO is the only group within Entergy that provides the Energy

10           and Fuel Management Class of services.             ETI does not duplicate

11           these services.

12

13                           F.       Summary of SPO Capital Charges

14   Q.      ARE YOU SUPPORTING ANY CAPITAL ADDITIONS INCLUDED IN THE

15           COMPANY’S REQUEST IN THIS PROCEEDING?

16   A.      Yes.    I am supporting the Company’s request for $219,406 in capital

17           charges associated with SPO-related services.        These capital projects

18           were closed to plant in service during the period July 2009 through June

19           2011 and are reasonable and necessary costs incurred for projects that

20           are used and useful in providing electric service. A detail of these charges

21           and the corresponding projects to which these charges were assigned, are

22           listed on Exhibit PJC-6, which reflects the following information:




2011 ETI Rate Case                                                       9-74
     Entergy Texas, Inc.                                                          Page 72 of 75
     Direct Testimony of Patrick J. Cicio
     2011 Rate Case


1            Column A                 Project Code Number

2            Column B                 Project Code Description

3            Column C                 Asset Class

4            Column D                 In-service Date

5            Column E                 Asset Location Description

6            Column F                 State Location

7            Column G                 Business Unit (“BU”)

8            Column H                 Non-Affiliate Charges Excluding Capital Suspense
9                                     and Reimbursements

10           Column I                 Reimbursements

11           Column J                 Represents capital suspense overhead costs
12                                    associated with administrators, engineers and
13                                    supervisors to the capital projects for which they
14                                    provide services. Each function charges their capital
15                                    suspense to a "Capital Suspense" project, which is
16                                    then allocated out to the appropriate capital projects.
17                                    Capital Suspense costs and the subsequent
18                                    allocation is separated by BU and function
19                                    combination to more accurately match such costs on
20                                    the actual projects worked on for each function within
21                                    a BU.

22           Column K                 Represents the portion of capital suspense overhead
23                                    costs (in Column J) from an affiliate.

24           Column L                 Represents the portion of capital suspense overhead
25                                    costs (in Column J) that are charged to the project by
26                                    ETI employees.

27           Column M                 Represents charges incurred by the ESI service
28                                    company and allocated out to the appropriate BUs
29                                    based on the ESI billing method assigned to the
30                                    project plus loaned resource charges incurred at one
31                                    BU and charged to another BU for services rendered
32                                    on behalf of that BU.




2011 ETI Rate Case                                                         9-75
     Entergy Texas, Inc.                                                         Page 73 of 75
     Direct Testimony of Patrick J. Cicio
     2011 Rate Case


1            Column N                 Represents the total affiliate portion of the charges
2                                     included in Column O, and is the total of Columns K,
3                                     and M.

4            Column O                 Represents the total amount of capital additions
5                                     closed to plant in service.

6            All of these costs relate to the capitalization of IT projects and research

7            and data services and modeling tools that support SPO’s activities.

8

9    Q.      PLEASE DESCRIBE THE CAPITAL PROJECTS THAT YOU SPONSOR

10           AS PART OF THE ENERGY AND FUEL MANAGEMENT CLASS.

11   A.      The 11 Project Codes shown on Exhibit PJC-6 are all IT capital projects

12           and research and data services and modeling tools that are related to

13           dispatch and operations.

14                   These capital projects relate to and support EMO’s dispatch and

15           operation responsibilities to meet projected electric demand reliably and at

16           the lowest reasonable cost, including, for example, enhancements to

17           various data systems and the development of tools to maintain

18           compliance with the Sarbanes-Oxley Act.

19

20   Q.      ARE ANY AFFILIATE COSTS INCLUDED IN THE REQUESTED

21           CAPITAL CHARGES?

22   A.      Yes, the necessary affiliate costs totaled $125,383 for SPO capital

23           projects shown in Column N of Exhibit PJC-6.




2011 ETI Rate Case                                                        9-76
     Entergy Texas, Inc.                                                         Page 74 of 75
     Direct Testimony of Patrick J. Cicio
     2011 Rate Case


1    Q.      WHY ARE AFFILIATE COSTS NECESSARY IN THE DEVELOPMENT

2            OF SPO IT APPLICATIONS?

3    A.      These costs are the result of employees of ESI (or an outside contractor of

4            ESI) providing design, implementation and project management services

5            for the various SPO IT capital projects. These charges are necessary in

6            order to design and implement IT systems that meet the needs of Entergy

7            System customers, including customers of ETI.

8

9    Q.      WHAT TYPES OF COSTS ARE INCURRED FOR THESE CAPITAL

10           PROJECTS?

11   A.      Expenses incurred as part of a capital project include equipment,

12           software, materials, supplies and any labor required to complete the

13           project. All costs are subject to the budget and cost control processes I

14           describe above.         The ESI labor costs are generally similar to those

15           incurred as O&M expense except that the labor is directly related to the

16           capital project, and the cost is capitalized as part of the total project cost.

17           These affiliate charges are reasonable for the same reasons discussed

18           above, are billed to ETI pursuant to the same principles and practices

19           previously discussed in my testimony and are at cost and are no higher

20           than the charges made to other affiliates for the same or similar services.




2011 ETI Rate Case                                                        9-77
     Entergy Texas, Inc.                                              Page 75 of 75
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     2011 Rate Case


1                                           IV.   CONCLUSION

2    Q.      DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?

3    A.      Yes.




2011 ETI Rate Case                                             9-78
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                 Page 1 of 83



      Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                                Original Sheet No. 1
      Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
      Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
      Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
      Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
      Entergy Texas, Inc., Rate Schedule FERC No. 181




                                          ENTERGY
                                  System Agreement
                                                  Agreement Among:
                                                Entergy Arkansas, Inc.
                                         Entergy Gulf States Louisiana, L.L.C.
                                               Entergy Louisiana, LLC
                                               Entergy Mississippi, Inc.
                                              Entergy New Orleans, Inc.
                                                 Entergy Texas, Inc.
                                                Entergy Services, Inc.




                                                            Little Rock




                                                                              Jackson




                                     Beaumont                           New
                                                                        Orleans




      Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                         Associate General Counsel

      Issued on:         November 21, 2008

      Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
      22, 2008.

2011 ETI Rate Case                                                                                         9-79
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                 Page 2 of 83



      Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                                Original Sheet No. 2
      Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
      Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
      Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
      Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
      Entergy Texas, Inc., Rate Schedule FERC No. 181




                                                           AGREEMENT

                                                                Among

                                          ENTERGY ARKANSAS, INC.
                                    ENTERGY GULF STATES LOUISIANA, L.L.C.
                                          ENTERGY LOUISIANA, LLC
                                          ENTERGY MISSISSIPPI, INC.
                                        ENTERGY NEW ORLEANS, INC.
                                            ENTERGY TEXAS, INC.
                                           ENTERGY SERVICES, INC.




      Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                         Associate General Counsel

      Issued on:         November 21, 2008

      Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
      22, 2008.

2011 ETI Rate Case                                                                                         9-80
                                                                                                                                              Exhibit PJC-1
                                                                                                                                         2011 TX Rate Case
                                                                                                                                               Page 3 of 83



      Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                                                            Original Sheet No. 3
      Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
      Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
      Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
      Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
      Entergy Texas, Inc., Rate Schedule FERC No. 181

                                                                               INDEX
                                                                                                                                          Sheet No.

      Preface.......................................................................................................................................... 4

      Article I                           Term of Agreement............................................................................... 6

      Article II                          Definitions ............................................................................................. 7

      Article III                         Objectives ............................................................................................ 13

      Article IV                          Obligations .......................................................................................... 16

      Article V                           Composition and Duties of the Operating Committee ...................... 23

      Article VI                          System Operations Center .................................................................. 27

      Signatory                           .............................................................................................................. 29

      Service Schedule MSS-1
                          Reserve Equalization .......................................................................... 30

      Service Schedule MSS-2
                          Transmission Equalization.................................................................. 38

      Service Schedule MSS-3
                          Exchange of Electric Energy Among the Companies....................... 44

      Service Schedule MSS-4
                          Unit Power Purchase........................................................................... 61

      Service Schedule MSS-5
                          Distribution of Revenue from Sales Made for the Joint Account
                          of All Companies ................................................................................ 71

      Service Schedule MSS-6
                          Distribution of Operating Expenses of System Operations Center .. 74

      Service Schedule MSS-7
                          Merger Fuel Protection Procedure ..................................................... 76




      Issued by:              Kimberly Despeaux                                                         Effective:               November 22, 2008
                              Associate General Counsel

      Issued on:              November 21, 2008

      Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
      22, 2008.

2011 ETI Rate Case                                                                                                                      9-81
                                                                                                                 Exhibit PJC-1
                                                                                                            2011 TX Rate Case
                                                                                                                  Page 4 of 83



   Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                                Original Sheet No. 4
   Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
   Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
   Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
   Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
   Entergy Texas, Inc., Rate Schedule FERC No. 181




                                                       AGREEMENT

                                                             Among

                                             ENTERGY ARKANSAS, INC.
                                ENTERGY GULF STATES LOUISIANA, L.L.C.
                                            ENTERGY LOUISIANA, LLC
                                            ENTERGY MISSISSIPPI, INC.
                                          ENTERGY NEW ORLEANS, INC.
                                                ENTERGY TEXAS, INC.
                                             ENTERGY SERVICES, INC.


            THIS AGREEMENT, first made and entered into on the 23rd day of April 1982, and
   subsequently amended, is by and among Entergy Arkansas, Inc., herein-after called EAI; Entergy Gulf
   States Louisiana, L.L.C., herein-after called EGSL or Gulf States Louisiana; Entergy Louisiana, LLC,
   hereinafter called ELL; Entergy Mississippi Inc., hereinafter called EMI; Entergy New Orleans Inc.,
   hereinafter called ENOI; Entergy Texas Inc., hereinafter called ETI, and Entergy Services, Inc.,
   hereinafter called Services, all of whose common stock is wholly owned by Entergy Corporation,
   hereinafter called Parent Company.


                                                       WITNESSETH
            0.01 WHEREAS, EAI, EGSL, ELL, EMI, ENOI, and ETI hereinafter called Companies,
   are the owners and operators of electric generation, transmission and distribution facilities with
   which they are engaged in the business of generating, transmitting and selling electric energy to
   the general public and to other electric distributing agencies; and




   Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                      Associate General Counsel

   Issued on:         November 21, 2008

   Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
   22, 2008.

2011 ETI Rate Case                                                                                          9-82
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                 Page 5 of 83



      Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                                Original Sheet No. 5
      Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
      Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
      Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
      Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
      Entergy Texas, Inc., Rate Schedule FERC No. 181




               0.02 WHEREAS, Services is an associated Service Company acting as the Agent for the
      Companies under the terms of the Middle South Utilities System Agency Agreement and the
      Middle South Utilities System Agency Coordination Agreement dated the 11th day of December
      1970; and

               0.03 WHEREAS, the Companies have been achieving substantial benefits for their
      customers by operating within the framework of an interconnection agreement dated April 11,
      1973; and

               0.04 WHEREAS, the individual Companies are interconnected by transmission lines and
      operated as a coordinated system from a central dispatching center; and

               0.05 WHEREAS, technological progress and changed economic conditions have
      necessitated the updating of the aforementioned interconnection agreement to continue to obtain
      the maximum benefits for them and their respective customers;


               NOW THEREFORE, the Parties hereto mutually understand and agree as follows:




      Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                         Associate General Counsel

      Issued on:         November 21, 2008

      Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
      22, 2008.

2011 ETI Rate Case                                                                                         9-83
                                                                                                                 Exhibit PJC-1
                                                                                                            2011 TX Rate Case
                                                                                                                  Page 6 of 83



      Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                                Original Sheet No. 6
      Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
      Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
      Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
      Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
      Entergy Texas, Inc., Rate Schedule FERC No. 181

                                                            ARTICLE I

                                                  TERM OF AGREEMENT


               1.01 This Agreement shall become effective on August 1, 1982, or such later date as may
      be fixed by any requisite regulatory approval or acceptance for filing and shall continue in full
      force and effect until terminated by mutual agreement of the Companies. Notwithstanding this,
      any Company may terminate its participation in this Agreement by ninety-six (96) months
      written notice to the other Companies hereto; and effective upon and after the date of
      implementation of retail open access in Texas, ETI shall terminate its participation in this
      Agreement, except as to Service Schedule MSS-2 (Transmission Equalization), consistent with
      Section 2.02 below.


               1.02 This Agreement shall supersede the agreement listed below: Agreement among
      Arkansas Power & Light Company, Arkansas-Missouri Power Company, Louisiana Power &
      Light Company, Mississippi Power & Light Company, New Orleans Public Service Inc. and
      Middle South Services, Inc. dated the 16th day of April 1973 in FPC Docket No. E-8130 as
      amended in FERC Docket No. ER79-277, FERC Docket No. ER80-366, and FERC Docket No.
      ER 81-405.

               1.03 This Agreement will be reviewed periodically by the Operating Committee to
      determine whether revisions are necessary to meet changing conditions. In the event that
      revisions are made by the parties hereto, and after requisite approval or acceptance for filing by
      the appropriate regulatory authorities, the Operating Committee will thereafter, for the purpose
      of ready reference to a single document, prepare for distribution to the Companies an amended
      document reflecting all changes in and additions to this Agreement with notations thereon of the
      date amended.




      Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                         Associate General Counsel

      Issued on:         November 21, 2008

      Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
      22, 2008.

2011 ETI Rate Case                                                                                         9-84
                                                                                                                 Exhibit PJC-1
                                                                                                            2011 TX Rate Case
                                                                                                                  Page 7 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                                Original Sheet No. 7
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181

                                                           ARTICLE II
                                                         DEFINITIONS

              For the purpose of this Agreement and of the Service schedules which are a part hereof,
     the following definitions shall apply:

              2.01 Agreement shall be this Agreement together with all attachments and service
     schedules applying thereto and any amendments made hereafter.

              2.02 Company shall be one of the Entergy System Operating Companies (EAI, ELL,
     EMI, ENOI, EGSL, ETI).


              2.03 Parent Company shall be Entergy Corporation.

              2.04 Agent shall be Entergy Services, Inc. which shall act as Agent for one or more of the
     Companies whenever appropriate.

              2.05 System shall be the interconnected coordinated systems of the Companies.

              2.06 Operating Committee shall be the administrative organization created under this
     Agreement to administer its provisions.

              2.07 Generating Unit shall be an electric generator, together with its prime mover and all
     auxiliary and appurtenant devices and equipment designed to be operated as a unit for the
     production of electric power and energy or as otherwise determined by the Operating Committee.




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                         9-85
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                 Page 8 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                                Original Sheet No. 8
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181




              2.08 Base Generating Units - shall be all generating units included in FERC accounts 310
     through 316 and whose fuel supply is coal and all generating units included in FERC accounts
     320 through 325 whose fuel supply is nuclear respectively, and such other generating units as
     may be designated from time to time by the Operating Committee.

              2.09 Intermediate Generating Units - shall be all generating units included in FERC
     accounts 310 through 316 and whose fuel supply is gas or oil and such other generating units as
     may be designated from time to time by the Operating Committee.

              2.10 Peaking Generating Units - shall be all generating units included in FERC accounts
     340 through 346 and such other generating units as may be designated from time to time by the
     Operating Committee.

              2.11 Hydraulic Production Units - shall be all generating units included in FERC
     accounts 330 through 336.

              2.12 Qualified Cogeneration Capacity shall be any capacity available from a cogeneration
     facility that qualifies under Subpart B of Part 292 of the Regulations of the FERC, 18 C.F.R. §
     292.201, et seq., as amended, or any successor provisions issued pursuant to Section 3(18)(B)of
     the Federal Power Act, and which, in accordance with Section 4.08 of this Agreement is under
     the control of the System Operator, to the extent practicable, and where the State or local
     regulatory body having jurisdiction over any Company which establishes the rate for a particular
     purchase also determines that the purchase will permit non-qualifying facility capacity costs to
     be avoided or, in the absence of such determination, to the extent that the Operating Committee
     determines that, in accordance with Section 4.01 of this Agreement and pursuant to Section
     292.304 of the FERC Regulations or any successor provision, the capacity will be employed to
     postpone generation that would otherwise be installed and thereby benefit the customers of all
     Companies. Individual Qualified Cogeneration Capacity below 10 mW will not be considered as



     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                         9-86
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                 Page 9 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                                Original Sheet No. 9
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181




     a power or energy source to any party to the System Agreement but will be considered as a
     negative load.


              2.13 Qualified Small Power Production Capacity shall be any capacity available from a
     small power production facility that qualifies under Subpart B of Part 292 of the FERC
     Regulations, 18 C.F.R. § 292.201, et seq., as amended, or any successor provisions issued
     pursuant to Section 3(17)(C) of the Federal Power Act, and which, in accordance with Section
     4.08 of this Agreement, is under the control of the System Operator, to the extent practicable,
     and where the State or local regulatory body having jurisdiction over any Company which
     establishes the rate for a particular purchase also determines that the purchase will permit non-
     qualifying facility capacity costs to be avoided or, in the absence of such determination, to the
     extent that the Operating Committee determines that, in accordance with Section 4.01 of this
     Agreement and pursuant to Section 292.304 of the FERC Regulations or any successor
     provision, the capacity will be employed to postpone generation that would otherwise be
     installed and thereby benefit the customers of all Companies. Individual Qualified Small Power
     Production Capacity below 10 mW will not be considered as a power or energy source to any
     party to the System Agreement but will be considered as a negative load.

              2.14 Capability shall be the net output in megawatts that can be produced by a generating
     unit under conditions specified by the Operating Committee, that is devoted to serving System
     load but excluding that portion of any unit the output of which has been sold to another
     Company (other than through MSS-3), or the input in megawatts available under contract from a
     supplying source, excluding the portion of such supply that has been sold to another Company
     (other than through MSS-3), including any capacity determined in Sections 2.12 or 2.13 above,
     plus the contractual amount of firm purchases with reserves available during the month from
     other systems adjusted upward by the ratio of Seller's Capability and Seller's Load Responsibility
     as determined in Section 10.02C.



     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                        9-87
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 10 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 10
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181



              2.15 System Capability shall be the arithmetical sum in megawatts of the individual
     Company Capabilities.


              2.16 Company Load Responsibility shall be determined as follows:

              (a)       To be used in conjunction with Service Schedules MSS-2 and MSS-6:
                        (i)       The average of the sum of the Company's twelve monthly hourly loads
                                  coincident with the System's monthly peak hour load for the period ended
                                  with the current month measured in megawatts. Each demand shall
                                  represent the simultaneous hourly input from all sources into the system of
                                  a Company, less the sum of the simultaneous hourly outputs to the
                                  systems of other interconnected utilities.
                        (ii)      Less the power supplied to others as sales for the joint account of all
                                  Companies.
              (b)       As of April 1, 2004,* to be used in conjunction with Service Schedules MSS-1
                        and MSS-5 and in conjunction with the allocation of a purchase of capacity and
                        energy for the joint account of all Companies under Section 4.02:
                        (i)       The average of the sum of the Company's twelve monthly hourly loads
                                  coincident with the System's monthly peak hour load for the period ended
                                  with the current month measured in megawatts.
                                  Each demand shall represent the simultaneous hourly input from all
                                  sources into the system of a Company, less the sum of the simultaneous
                                  hourly outputs to the systems of other interconnected utilities.
                        (ii)      Less the power supplied to others as sales for the joint account of all
                                  Companies.
     *        In the calculation pursuant to Section 2.16(b)(iii), the full amount of the interruptible load has
     been removed as of April 1, 2004 (as opposed to phased-in over a twelve month period).




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                        9-88
                                                                                                                 Exhibit PJC-1
                                                                                                            2011 TX Rate Case
                                                                                                                 Page 11 of 83



    Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 11
    Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
    Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
    Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
    Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
    Entergy Texas, Inc., Rate Schedule FERC No. 181

                       (iii)     Less loads served under interruptible tariffs or contracts, where the
                                 interruptible load excluded at the time of the system’s monthly peak hour load
                                 (which does not include the excludable interruptible load determined herein) is
                                 to be that load that, pursuant to said tariff or contract, is subject to interruption.
                                 To the extent practical the determination of what loads are interruptible shall
                                 be based on actual data and if it is not practical, shall be based on reasonable
                                 estimates.


             2.17 System Load Responsibility:
             (a)       To be used in conjunction with Service Schedules MSS-2 and MSS-6 shall be the
                       arithmetical sum in megawatts of the individual Company Load Responsibilities
                       derived pursuant to Section 2.16(a).
             (b)       As of April 1, 2004, to be used in conjunction with Service Schedules MSS-1 and
                       MSS-5 and in conjunction with the allocation of a purchase of capacity and
                       energy for the joint account of all Companies under Section 4.02 shall be the
                       arithmetical sum in megawatts of the individual Company Load Responsibilities
                       derived pursuant to Section 2.16(b).

             2.18 Responsibility Ratio of a Company shall be the ratio obtained by dividing the load
    responsibility of that company by the System Load Responsibility.

             2.19 Capability Responsibility of a Company shall be the System Capability multiplied
    by the Responsibility Ratio for that Company.

             2.20 Pool Energy shall be the energy generated by a Company in excess of its own
    requirements, or acquired by any Company under economic dispatch or as directed by the
    System Operator, that goes to supply requirements of other Companies. Such energy shall in all
    cases be nonfirm, that is, it has no guaranteed or assured availability.




    Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                       Associate General Counsel

    Issued on:         November 21, 2008

    Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
    22, 2008.

2011 ETI Rate Case                                                                                          9-89
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 12 of 83



      Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 12
      Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
      Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
      Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
      Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
      Entergy Texas, Inc., Rate Schedule FERC No. 181




               2.21 Cogeneration or Small Power Production Energy shall be the energy acquired by
      any Company from qualified facilities whether or not acquired under economic dispatch.

               2.22 Transmission Responsibility of a Company shall be the System Net
      Inter-Transmission Investment multiplied by the Responsibility Ratio for that Company.

               2.23 System Net Inter-Transmission Investment shall be the arithmetical sum of the
      individual Company Net Inter-Transmission Investments.

      *        2.24 * Typographical error - 2.24 not used in numbering of definitions.

               2.25 Day shall be a continuous 24-hour period beginning at midnight CST, or such other
      time as may be agreed upon by the Operating Committee.

               2.26 Month shall be a calendar month.

               2.27 Year shall be calendar year.

               2.28 Power shall be the rate of doing work and shall be expressed in kilowatts (kW),
      megawatts (mW), or gigawatts (gW).

               2.29 Energy shall be work and shall be expressed in kilowatt hours (kWh),
      megawatt-hours (mWh), or gigawatt-hours (gWh).




      Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                         Associate General Counsel

      Issued on:         November 21, 2008

      Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
      22, 2008.

2011 ETI Rate Case                                                                                        9-90
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 13 of 83



      Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 13
      Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
      Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
      Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
      Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
      Entergy Texas, Inc., Rate Schedule FERC No. 181

                                                           ARTICLE III
                                                          OBJECTIVES


               3.01 The purpose of this Agreement is to provide the contractual basis for the continued
      planning, construction, and operation of the electric generation, transmission and other facilities
      of the Companies in such a manner as to achieve economies consistent with the highest
      practicable reliability of service, subject to financial considerations, reasonable utilization of
      natural resources and minimization of the effect on the environment. This Agreement also
      provides a basis for equalizing among the Companies any imbalance of costs associated with the
      construction, ownership and operation of such facilities as are used for the mutual benefit of all
      the Companies.

               3.02 It is recognized by the Companies that economies of scale and integrated operations
      require that the planning, construction and operation of the bulk power supply and related
      facilities of the Companies be on a coordinated basis.

               3.03 It is recognized that the Companies have traditionally used natural gas as their
      primary boiler fuel and that curtailments by suppliers have necessitated a conversion to oil as
      boiler fuel. Minimizing current and future costs of electricity and reducing energy dependence
      on oil and gas require the Companies to move toward a new fuel base of coal and nuclear.

               3.04 It is recognized that these new coal and nuclear units will be Base Generating Units
      as defined in 2.08 and will be units of the larger ratings in generating stations of large size,
      strategically located with regard to fuel, water supply and electric load.

               3.05 It is the long term goal of the Companies that each Company have its proportionate
      share of Base Generating Units available to serve its customers either by ownership or purchase.




      Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                         Associate General Counsel

      Issued on:         November 21, 2008

      Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
      22, 2008.

2011 ETI Rate Case                                                                                         9-91
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 14 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 14
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181




     Any Company which has generating capacity above its requirements, which desires to sell all or
     any portion of such excess generating capacity and associated energy, shall offer the right of first
     refusal for this capacity and associated energy to the other Companies under Service Schedule
     MSS-4 Unit Power Purchase.

              3.06 It is recognized that the installation of large base generating stations at locations, in
     many cases necessarily remote from major load centers, will require the installation of additional
     major high voltage and extra high voltage transmission lines and substations to connect these
     large generating stations to the major load centers in a manner to assure the highest practicable
     reliability of service.

              3.07 It is recognized that reliability of service and economy of operation require that the
     energy supply to the system be controlled, to the extent practicable, from a centralized
     dispatching office and that this will require adequate communication facilities and the provision
     of economic dispatch computer facilities and automatic controls of generation.

              3.08 By jointly planning on a systemwide basis for the construction and operation of
     these major facilities:

              (a)       The combined loads of the Companies can be supplied with less aggregate
                        installed capacity; and
              (b)       Installations of additional capacity can be made at lower cost per kW because of
                        the large unit sizes; and
              (c)       The new installations will be more economical and require less operating labor
                        and maintenance per kW because of the larger unit sizes; and
              (d)       The strengthened transmission system will make possible a fuller utilization of the
                        capability of the lower cost generating units of the System; and




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                        9-92
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 15 of 83



      Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 15
      Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
      Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
      Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
      Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
      Entergy Texas, Inc., Rate Schedule FERC No. 181




               (e)        Emergency conditions in any part of the System or other systems in adjacent
                         areas can be met with less probability of impairment of service to the general
                         public.

               3.09 It is intended that each Company shall be willing and able to provide its portion of
      the major facilities determined to be necessary and each Company shall share in the benefits and
      pay its share of the costs of coordinated operations as agreed upon in accordance with Service
      Schedules to be attached hereto from time to time and made a part hereof.




      Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                         Associate General Counsel

      Issued on:         November 21, 2008

      Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
      22, 2008.

2011 ETI Rate Case                                                                                         9-93
                                                                                                                 Exhibit PJC-1
                                                                                                            2011 TX Rate Case
                                                                                                                 Page 16 of 83



      Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 16
      Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
      Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
      Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
      Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
      Entergy Texas, Inc., Rate Schedule FERC No. 181

                                                           ARTICLE IV
                                                         OBLIGATIONS


               4.01 Production Facilities
               Each Company shall normally own, or have available to it under contract, such
      generating capability and other facilities as are necessary to supply all of the requirements of its
      own customers.
               Each Company shall furnish the Operating Committee, at the time and in the manner
      designated, estimates of its annual peak load for the next succeeding 10-year period, or such
      period as may be required, together with estimates of its capability available from generating
      units in operation, under construction or already approved, capability available from other
      sources under contract and Qualified Cogeneration Capacity or Qualified Small Power
      Production Capacity in accordance with Sections 2.12 and 2.13 of this Agreement.
               The Operating Committee shall then determine a generation addition plan to provide
      capacity for the projected system load and furnish reliable service to customers at the lowest cost
      consistent with sound business practice. Any anticipated large blocks of power sales not
      previously submitted to the Operating Committee shall be submitted to the Operating Committee
      as soon as load information is available so that appropriate capacity can be scheduled into the
      generation addition plan.
               Each Company that installs a Generating Unit will make the necessary financial
      arrangements and promptly proceed with the design and construction of the unit to meet the
      "in-service" date of the generation addition plan.
               Any Capability in excess of the Capability Responsibility of a Company that may exist in
      the system of one or more Companies as a result of installation of facilities in accordance with
      the provisions of the generation addition plan shall be equalized among the Companies in
      accordance with the provisions of the applicable Service Schedule.




      Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                         Associate General Counsel

      Issued on:         November 21, 2008

      Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
      22, 2008.

2011 ETI Rate Case                                                                                         9-94
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 17 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 17
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181




              4.02 Purchased Capacity & Energy
              The Companies, with the consent of or under conditions specified by the Operating
     Committee, may agree to a contract by one or more of them, for the purchase of capacity and/or
     energy from outside sources for the account of a Company or Companies.
              If purchased by a Company for its own account, the capacity shall be included by the
     purchasing Company in its Capability to the extent provided by the applicable Service Schedule.
     The energy purchased shall be considered as part of the purchasing Company's energy supply.
              If purchased by a Company for the joint account of less than all of the Companies, the
     capacity and energy shall be allocated among the purchasing Companies in any manner mutually
     agreeable to them.
              If purchased by a Company for the joint account of all the Companies, the capacity and
     energy shall be allocated to each Company in proportion to its Responsibility Ratio based on
     Sections 2.16(b) and 2.17(b) in effect at the end of the preceding month. Each Company shall
     include its allocated portion of the capacity, so purchased, in its Capability to the extent provided
     by the applicable Service Schedule and shall include its portion of the energy so purchased in its
     energy supply. Each Company shall pay for capacity and energy allocated to it hereunder at the
     rates paid by the Company making the purchase.

              4.03 Energy Purchased by Services
              Services, through the System Operations Center, may purchase energy under economic
     dispatch or emergency conditions, in accordance with Article VI paragraph 6.02 of this
     Agreement, for the joint account of all the Companies. The energy purchased shall be allocated
     to each Company in proportion to its Responsibility Ratio in effect at the end of the preceding
     month.




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                        9-95
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 18 of 83



      Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 18
      Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
      Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
      Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
      Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
      Entergy Texas, Inc., Rate Schedule FERC No. 181



               4.04 Capacity and Energy Exchanged with Outside Systems
               Capacity and energy may be delivered to or received from an outside system under
      agreements providing for a return in kind. The accounting for such deliveries and receipts shall
      be as follows:
               (a)       If the System supplies first, the obligations to supply shall be prorated to each
                         Company, in proportion to its Responsibility Ratio in effect as of the preceding
                         October 31st, and the capacity and energy which each Company is entitled to
                         receive in return shall be equal to the obligation to supply.
               (b)       If the System receives first, the capacity and energy to be received shall be
                         prorated to each Company in proportion to its Responsibility Ratio in effect as of
                         the preceding October 31st, and each Company shall be obligated to supply in
                         return the amount of capacity and energy that it was entitled to receive.

               4.05 Sales to Others for the Joint Account of All the Companies
               Sales of capacity and energy to others for which any Company does not wish to assume
      sole responsibility, shall, with the consent of or under conditions specified by the Operating
      Committee, be made by the Company having direct connection with such others, for the joint
      account of all the Companies, and the net balance derived from such sales shall be divided
      among the Companies as provided in the applicable Service Schedule.

               4.06 Transmission Facilities
               The Companies own and operate extensive transmission systems traversing their
      operating areas and interconnecting with each other, as well as with the transmission systems of
      adjacent utilities.
               It is agreed that portions of each Company's bulk power transmission system shall be
      equalized in accordance with the applicable Service Schedule so that the ownership costs of
      those transmission facilities shall be distributed equitably among the Companies.




      Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                         Associate General Counsel

      Issued on:         November 21, 2008

      Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
      22, 2008.

2011 ETI Rate Case                                                                                        9-96
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 19 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 19
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181

              The Operating Committee shall make studies of bulk power transmission facilities and
     agree upon the facilities that will be required to transmit the power supply from generating or
     other sources to the load centers. The facilities agreed upon shall be built to comply with a time
     schedule determined by the Operating Committee and shall be adequate to provide the bulk
     power transmission system requirements with due allowances for contingencies that may
     reasonably be expected. The Operating Committee shall agree on the general routes of bulk
     power transmission lines, the voltages and conductor sizes, and the location of substations which
     are covered by this Agreement.

              4.07 Communication and Other Facilities
              The Companies shall provide communication and other facilities, determined by the
     Operating Committee to be necessary for metering, control, protection and dispatch of the
     production and transmission facilities, and for such other purposes as may be necessary or
     desirable for the operation of the Companies' Systems.

              4.08 Dispatch
              Under general direction of the Operating Committee, Services will operate a centralized
     operations center properly equipped and staffed to dispatch the capacity and energy capability of
     the Companies, in the efficient, economical, and reliable manner as provided in this Agreement.
     All generating units, included in System Capability under this Agreement, presently in operation
     or installed in the future, shall be equipped with such controls as may be determined by the
     Operating Committee to be necessary to accomplish such centralized economic dispatch.
              It is recognized by the Companies that, because of such economic dispatch, a Company
     may not, at all times, be supplying the energy requirements of its system, but may be taking
     energy from the resources of the other Companies or supplying energy to the other Companies.
     The payments or charges for such energy exchange shall be as provided in the applicable Service
     Schedule.




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                        9-97
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 20 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 20
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181



              4.09 Records and Reports
              Services shall keep such records as may be necessary for the efficient administration of
     the Agreement, and shall make such records available to any Company on request. Each
     Company shall make all reports requested by the Operating Committee within the time
     prescribed.

              4.10 Regulatory Authorization
              This Agreement is subject to certain regulatory approvals and each Company shall
     diligently seek all necessary regulatory authorization for this Agreement and the performance of
     its obligations thereunder.

              4.11 Effect on Other Agreements
              This Agreement shall not modify the obligations of any Company under any Agreement
     between that Company and others not parties to this Agreement in effect at the date of this
     Agreement.

              4.12 Service Schedules
              The basis of compensation for the use of facilities and for the capacity and energy
     provided or supplied by a Company to another Company or Companies under this Agreement
     shall be in accordance with arrangements agreed upon from time to time among the Companies.
     Such arrangements shall be in the form of Service Schedules, each of which, when signed by the
     parties hereto, and approved or accepted for filing by appropriate regulatory authority shall be
     attached to and become a part of this Agreement.
              Each Company reserves the right to unilaterally seek amendments or changes in the terms
     and conditions of service and increases or decreases in the rates and charges provided in any of
     the Service Schedules from any regulatory body having or acquiring jurisdiction thereover.




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                        9-98
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 21 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 21
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181



              4.13 Measurements
              All capacity and energy measurements, such as between the systems of the Companies,
     shall be made at or corrected to the points of interconnection unless otherwise agreed to by the
     Operating Committee.

              4.14 Billings
              Bills for services rendered hereunder shall be calculated in accordance with applicable
     Service Schedules, and shall be issued on the fifth working day of the month following that in
     which such service was rendered and shall be payable on or before the 15th day of such month.
     After the 20th day, interest shall accrue on any balance due at the rate as determined in Section
     35.19a(2)iii of the FERC Regulations, or at such other rate established by the Operating
     Committee.

              4.15 Waivers
              Any waiver at any time by a Company of its rights with respect to a default by any other
     Company under this Agreement, shall not be deemed a waiver with respect to any subsequent
     default.

              4.16 Successors and Assigns
              This Agreement shall inure to the benefit of and be binding upon the successors and
     assigns of the respective Companies here to, but shall not be assignable by any Company without
     the written consent of the other Companies, except upon foreclosure of a mortgage or deed of
     trust.

              4.17 Amendment
              This Agreement may be changed, amended, or supplemented, only by an instrument in
     writing, signed by all the Companies.




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                        9-99
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 22 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 22
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181



              4.18 Independent Contractors
              It is agreed among the Companies that by entering into this Agreement providing for the
     coordinated planning, construction and operation of power production, transmission,
     communications and other facilities of the Companies, the Companies shall not become partners,
     but as to each other and to third persons, the Companies shall remain independent contractors in
     all matters relating to this Agreement.

              4.19 Responsibility for Loss or Damage
              Each Company shall defend, indemnify, and save harmless the other Companies, against
     liability, loss, costs and expenses on account of any injury or damage to persons or property
     occurring on or in connection with its facilities on its side of any of the points of interconnection,
     except to the extent such injury or damage was caused by the sole or contributory negligence of
     another Company, its agent or employees.




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                        9-100
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 23 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 23
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181

                                                           ARTICLE V
                    COMPOSITION AND DUTIES OF THE OPERATING COMMITTEE


              5.01 Operating Committee
              An Operating Committee shall be the administrative organization of this Agreement and
     shall consist of members designated by the chief executive officers of each Company and by the
     chief executive officer of the Parent Company. Such designation shall be by written notice to the
     Secretary of the Operating Committee with copies to each of the other Companies. The
     Companies and the Parent Company may change its designated members at any time by written
     notice to the Secretary of the Operating Committee and each of the other Companies.

              5.02 Officers of the Operating Committee
              The Operating Committee shall have the following officers with duties as designated:
              (a)       Chairman - The Chairman shall issue calls for and shall preside at meetings of the
                        Operating Committee. He shall have responsibility for the general coordination
                        of the Operating Committee functions among the various members.
              (b)       Vice Chairman - The Vice Chairman shall perform the duties of the Chairman in
                        his absence or incapacity.
              (c)       Secretary - The Secretary shall be responsible for keeping the minutes of the
                        meetings of the Operating Committee and for preparing copies thereof and for
                        distributing them to the Companies. The Secretary shall be responsible for
                        obtaining written approval from the Companies for any acts or decisions of the
                        Operating Committee which may require such written approval, and shall be
                        responsible for distributing copies of such approvals to the Companies.
              The Chairman and Vice Chairman shall be elected from the members by majority vote at
     the first meeting held in each calendar year and shall take office immediately upon being elected.
              The Secretary shall be designated by the Operating Committee.




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                         9-101
                                                                                                                 Exhibit PJC-1
                                                                                                            2011 TX Rate Case
                                                                                                                 Page 24 of 83



      Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 24
      Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
      Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
      Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
      Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
      Entergy Texas, Inc., Rate Schedule FERC No. 181



               5.03 Meeting Dates
               The Operating Committee shall hold meetings at least quarterly and at any time upon the
      request of a member, and shall keep minutes of its proceedings.

               5.04 Decisions
               All decisions of the Operating Committee shall be by a majority vote. For the purposes
      of voting, the Parent Company shall have twenty (20) percent of the vote and the remaining
      eighty (80) percent shall be divided among the Companies in proportion to each Company's
      Responsibility Ratio in effect as of the preceding December 31st.

               5.05 Attendance at Meetings
               Each Company and the Parent Company shall be represented at each Operating
      Committee meeting by their members on the Committee or a proxy designated by the member or
      chief executive officer. Such proxy member need not be an employee of the Company
      represented.

               5.06 Duties
               The Operating Committee shall:
               (a)       Be responsible for the day-to-day administration of the Agreement and for the
                         filing of this Agreement and any amendments thereto with the Federal Energy
                         Regulatory Commission for approval or acceptance for filing and for distributing
                         copies of such filings to the Companies.
               (b)       Make the studies required to fulfill the obligations agreed to in the Article IV of
                         this Agreement, and its decisions shall become the basis for the installation of
                         generation, bulk power transmission, communication, and other facilities
                         necessary for the supply of capacity and energy to the System.




      Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                         Associate General Counsel

      Issued on:         November 21, 2008

      Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
      22, 2008.

2011 ETI Rate Case                                                                                         9-102
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 25 of 83



    Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 25
    Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
    Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
    Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
    Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
    Entergy Texas, Inc., Rate Schedule FERC No. 181




             (c)       Determine the amount of and require installation of adequate reserves of System
                       Capability to assure, insofar as practicable, the continuous supply of capacity and
                       energy to the major load centers of the System.
             (d)       Establish safe loading criteria for generating units, transmission lines and any
                       other facilities necessary for the supply of power and energy to the major load
                       centers of the System.
             (e)       Promulgate whatever standards may be required for the safe and reliable
                       operation of the System.
             (f)       Consult with and provide general supervision for Services in employing and
                       supervising a System Operator and provide for such assistance as needed.
             (g)       Determine the need for and generally supervise the keeping of records and the
                       making of such reports as are deemed necessary or appropriate.
             (h)       Determine the need for and generally supervise communications, interchange and
                       automatic generation control, metering, economic dispatch and relaying facilities
                       necessary for the purpose of this Agreement.
             (i)       Make any determinations required for the purpose of administering any schedules
                       subject to its administration.
             (j)       Study and determine from time to time additions or changes in facilities necessary
                       to keep abreast of the production and transmission requirements of the System.
             (k)       Provide for and coordinate safe dispatching, switching and other routine procedures.
             (l)       Provide for proper distribution of spinning reserves and the supply of reactive kVa.




    Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                       Associate General Counsel

    Issued on:         November 21, 2008

    Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
    22, 2008.

2011 ETI Rate Case                                                                                         9-103
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 26 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 26
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181




              (m)       Establish, amend, supplement or terminate from time to time rules, procedures or
                        practices as necessary to insure functioning of the System within the scope of this
                        Agreement.
              (n)       Coordinate negotiations with others from time to time for interchange and sale of
                        power and energy.
              (o)       Coordinate arrangements for the sale and delivery to others on a profitable basis,
                        of power and energy not required for System purposes.
              (p)       Coordinate arrangements from time to time to procure for the Companies, or for
                        their account, such power and energy from external sources as may be required or
                        will result in savings to the Companies.
              (q)       Keep abreast of all environmental factors as they affect the operation of the
                        System in order to comply with all established criteria for minimizing pollution.
              (r)       Undertake any other duties that may from time to time be assigned to it or deemed
                        appropriate.

              5.07 Employment of Consultants
              The Operating Committee, in the performance of its duties, may employ such technical
     and consulting services as warranted.

              5.08 Expenses of Committee
              Each Company (except the Parent Company) shall pay the expenses of its representatives
     on the Operating Committee. The expenses of the representatives of the Parent Company shall
     be paid by Services. Any other expenses of the Committee shall be prorated among the
     Companies as determined by the Operating Committee.




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                        9-104
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 27 of 83



      Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 27
      Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
      Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
      Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
      Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
      Entergy Texas, Inc., Rate Schedule FERC No. 181

                                                           ARTICLE VI
                                            SYSTEM OPERATIONS CENTER


               6.01 System Operations Center
               The operation of the System shall be controlled by the System Operations Center which
      is operated by Services.

               6.02 Duties
               Services through the System Operations Center shall:
               (a)       Determine the most effective scheduling of sources for the reliable supply of
                         power and energy on an economical basis to the Companies.
               (b)       Supervise the operation and maintenance of computer facilities specified by the
                         Operating Committee for the following purposes:
                         1. Economic system dispatch,
                         2. Determination of billing information, and
                         3. Determination of other data required by the Operating Committee.
               (c)       Supervise safe switching procedures and other routine procedures in the system.
               (d)       Determine the availability of energy for purchase from or sale to outside systems
                         on an economical basis under effective contracts and arrange for and schedule
                         such transactions.
               (e)       Coordinate the operation of communication facilities owned or leased by the
                         Companies to provide the communication essential to the safe, reliable and
                         economical operation of the System.
               (f)       Maintain such records and prepare such reports as the Operating Committee
                         designates.




      Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                         Associate General Counsel

      Issued on:         November 21, 2008

      Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
      22, 2008.

2011 ETI Rate Case                                                                                        9-105
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 28 of 83



      Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 28
      Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
      Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
      Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
      Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
      Entergy Texas, Inc., Rate Schedule FERC No. 181




               6.03 Expenses
               All expenses of the Systems Operations Center shall be paid by Services and billed
      monthly to each Company in accordance with the applicable Service Schedule.




      Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                         Associate General Counsel

      Issued on:         November 21, 2008

      Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
      22, 2008.

2011 ETI Rate Case                                                                                        9-106
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 29 of 83



      Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 29
      Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
      Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
      Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
      Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
      Entergy Texas, Inc., Rate Schedule FERC No. 181




               IN WITNESS WHEREOF each of the Companies has caused these presents to be signed
      in its name and on its behalf by its President, attested by its Secretary, both being duly
      authorized.


      Attest                                 ARKANSAS POWER & LIGHT COMPANY
      Original signed by                                   Original signed by
      R. J. Estrada                                        Jerry Maulden
      Assistant Secretary                                  President


      Attest                                 LOUISIANA POWER & LIGHT COMPANY
      Original signed by                                    Original signed by
      W. H. Talbot                                          J. M. Wyatt
      Secretary                                             President


      Attest                                 MISSISSIPPI POWER & LIGHT COMPANY
      Original Signed by                                      Original signed by
      R. J. Estrada                                           D. C. Lutken
      Assistant Secretary                                     President


      Attest                                 NEW ORLEANS PUBLIC SERVICE INC.
      Original signed by                                    Original signed by
      William C. Nelson                                     James M. Cain
      Secretary                                             President


      Attest                                 MIDDLE SOUTH SERVICES, INC.
      Original signed by                                    Original signed by
      D. E. Stapp                                           Frank G. Smith
      Secretary                                             President




      Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                         Associate General Counsel

      Issued on:         November 21, 2008

      Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
      22, 2008.

2011 ETI Rate Case                                                                                         9-107
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 30 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 30
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181



                                              SERVICE SCHEDULE MSS-1
                                               RESERVE EQUALIZATION
            10.01 Purpose
            The purpose of this Service Schedule is to provide the basis for equalizing the capability
     and ownership cost incidental to such capability among the Companies in such a manner that the
     capability and reserves of each Company after equalization shall be equal to its Capability
     Responsibility.

           10.02 Company Capability
           A Company's Capability shall be determined monthly and shall be the sum of available
     owned or leased generating units, purchases and seasonal or other energy exchange from
     demonstrated reliable sources as follows:
           (a)     The total capability of available generating units owned, operated under
                        Operating Agreements for its own benefit, or leased by such Company, devoted to
                        serving System load but excluding that portion of any unit owned or leased by
                        such Company that has been sold or leased to another Company (other than
                        through MSS-3). Such units shall be included at their demonstrated net output
                        measured in megawatts under conditions established by the Operating Committee.
                        A unit is considered available to the extent the capability can be demonstrated and
                        (1) is under the control of the System Operator, or (2) is down for maintenance or
                        nuclear refueling, or (3) is in extended reserve shutdown (ERS) with the intent of
                        returning the unit to service at a future date in order to meet Entergy System
                        requirements. The Operating Committee's decision to consider an ERS unit to be
                        available to meet future System requirements shall be evidenced in the minutes of
                        the Operating Committee and shall be based on consideration of current and
                        future resource needs, the projected length of time the unit would be in ERS
                        status, the projected cost of maintaining such unit, and the projected cost of
                        returning the unit to service. A unit is considered unavailable if in the judgment




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                         9-108
                                                                                                               Exhibit PJC-1
                                                                                                          2011 TX Rate Case
                                                                                                               Page 31 of 83




     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 31
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181

                        of the Operating Committee it is of insufficient value in supplying system loads
                        because of (1) obsolescence, (2) physical condition, (3) reliability, (4) operating
                        cost, (5) start-up time required, or (6) lack of due-diligence in effecting repairs or
                        nuclear refueling in the event of a scheduled or unscheduled outage.


              The generating units of Gulf States that were in extended reserve shutdown on the date of
              the merger of Entergy and Gulf States, shall not be considered available for the purpose
              of determining Capability in the Service Schedule MSS-1 Reserve Equalization
              calculation until the units are brought into service.
              If, as part of a settlement or judgment adverse to Gulf States in Cajun Electric Power
              Cooperative, Inc. v. Gulf States Utilities Co., Civil Action No. 89-474-B (M.D. La.)
              and/or Southwest Louisiana Electric Membership Corp. and Dixie Electric Membership
              Corp. v. Gulf States Utilities Co., Civil Action No. 92-2129 (W.D. La.), Gulf States
              acquires Cajun Electric Power Cooperative, Inc.’s 30 percent share of the River Bend
              Nuclear Generating Facility (River Bend) (or any portion thereof), then the net output in
              megawatts associated with such share shall not be considered available for the purpose of
              determining Capability in the Service Schedule MSS-1 Reserve Equalization calculation.
              (b)       The contract quantity of capacity in megawatts purchased without reserves by the
                        Company.
              (c)       The contract quantity of firm capacity in megawatts purchased plus an additional
                       amount as developed from the following formula:
                              A = FP x SC - FP
                                   (SL - FP)
              where:
                        A=        Amount, in megawatts (mW), to be added to contract quantity of firm
                                  capacity purchased.




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                       9-109
                                                                                                               Exhibit PJC-1
                                                                                                          2011 TX Rate Case
                                                                                                               Page 32 of 83




     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 32
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181

                        FP = Amount of firm purchase in Mw
                        SL = Seller's load responsibility in mW, determined by calculating the average of
                                  the Seller's monthly hour peak loads for the twelve month period ending
                                  with the current month. Each such peak load shall represent the
                                  simultaneous hourly input from all sources into the Seller's system, less
                                  the sum of the simultaneous hourly outputs to the systems of other
                                  interconnected utilities.
                        SC = Seller’s total capability which shall be determined monthly and shall be the
                                  sum of the net demonstrated capabilities of Seller’s owned or leased
                                  generating units and the contract quantity of capacity purchased by Seller,
                                  all measured in mW.
              (d)       That portion of the contract quantity of capacity in megawatts purchased with or
                        without reserves, for the joint account of all the Companies as allocated to the
                        Company on the basis of Section 4.02.
              (e)       That portion of the contract quantity of capacity in megawatts received under any
                        seasonal or other exchange with outside suppliers for the joint account of all
                        Companies, as allocated to the Company on the basis of its Responsibility Ratio.
              (f)       Cogeneration or Small Power Production Capacity in accordance with Sections
                        2.12 and 2.13. The Operating Committee shall have the authority to allocate any
                        such capacity to one or more of the Companies in accordance with FERC Opinion
                        Nos. 246 and 246-A.
              10.03 Basis of Reserve Equalization
              Company Capability in excess of the Capability Responsibility of any Company shall be
     allocated among the Companies so that the resultant capability and reserves of each Company
     shall be equal to its Capability Responsibility.

              ER = CC - SC x CLR
                             SLR


     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                       9-110
                                                                                                               Exhibit PJC-1
                                                                                                          2011 TX Rate Case
                                                                                                               Page 33 of 83




     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 33
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181

     where:
     ER = Equalized Reserve
     CC = Company Capability                                   (Section 2.14)
     SC = System Capability                                    (Section 2.15)
     CLR = Company Load Responsibility                         (Section 2.16 (b))
     SLR = System Load Responsibility                          (Section 2.17 (b))


              If more than one Company has Company Capability in excess of its Capability
     Responsibility, the excess of each such Company from its Intermediate Generating Units, as
     defined in Section 2.09 shall be allocated to each deficient Company in the ratio of such
     Company's deficiency to the sum of the deficiencies of the deficient Companies.


              10.04 Reserve Equalization Payment
              For the reserve allocated in accordance with Section 10.03, the Company or Companies
     having an excess shall receive, from the Company or Companies having a deficiency, an
     equalization payment, determined in accordance with the method hereinafter described, for such
     reserve so allocated each month.


              10.05 Investment in Intermediate Reserve Generating Units
              The generating units to be reflected in determining the costs to be billed under this
     Service Schedule are those that serve as reserves to the System and shall be defined by reference
     to their average annual heat rate. The Reserve Generating Units for each Party (based on Federal
     Energy Regulatory Commission's Uniform System of Accounts Prescribed for Public Utilities
     and Licensees) shall be those gas- and oil-fired units that had an annual average heat rate in the
     preceding calendar year of at least 10,000 Btu per kilowatt=hour. For Reserve Generating Units
     that were not in commercial operation for all of the preceding calendar year, the heat rate used to
     determine eligibility under this provision shall be specified by the Operating Committee. The


     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                       9-111
                                                                                                               Exhibit PJC-1
                                                                                                          2011 TX Rate Case
                                                                                                               Page 34 of 83




     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 34
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181

     investment in such Reserve Generating Units shall be determined as follows:
              (a)       The cost includable for all such units in Accounts 310, 311, 312, 313, 314, 315
                        and 316.
              (b)       The cost of step-up transformers, circuit breakers, and switching equipment etc.
                        included in Account 353 and required to connect all such units to the transmission
                        system.


              10.06 Determination of Monthly Billing Charge _
              The Monthly Charge (MC) per kW for billings under Reserve Equalization shall be
     determined for each Company based upon the previous year's operating results. The MC will be
     based on the average of all units included as Intermediate Generating Units as included in
     Sections 10.05 (a) and (b).


     MC = (1/12) RB x (CM + F) + D + PT + I + FT + OM
                               C
     where:
              CM =             the weighted average cost of capital as determined in the following manner:
              CM =          (DR x i) + (PR x p) + (ER x c)
                  C = The sum of capacity in kW for the generating units in RB
                  DR = Ratio of Debt Capital at Dec. 31 of the previous year
                  PR = Ratio of Preferred Stock at Dec. 31 of the previous year
                  ER = Ratio of Common Stock at Dec. 31 of the previous year
                  i =   Average embedded cost of debt capital outstanding at Dec. 31 of the previous
                        year
                  p =   Average embedded cost of preferred stock outstanding at Dec. 31 of the previous
                         year
                  c =   Return on Common Equity at 11.0%



     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                       9-112
                                                                                                               Exhibit PJC-1
                                                                                                          2011 TX Rate Case
                                                                                                               Page 35 of 83




   Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 35
   Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
   Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
   Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
   Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
   Entergy Texas, Inc., Rate Schedule FERC No. 181

                D = The amount of depreciation for the preceding year as reported on page 429 of the
                      Company FERC Form No. 1 report as related to Intermediate Generating Units
                      and associated equipment required to connect generating equipment to the
                      transmission system.
                F =   Federal and State Income Taxes determined from the following formulae:
                       F = T x (CM - DR x i)
                           (1 - T)
            where:
            T =       f + s - fs when federal tax is not deductible in computing state tax, and
                      T =       (f + s - 2fs) when federal tax is deductible in computing
                                  (1 - fs)
                                state tax, and
                      f =       Federal Income Tax Rate
                      s =       State Income Tax Rate
            RB = The amount as of December 31, of the preceding year reflected in Plant Accounts
                      310, 311, 312, 313, 314, 315 and 316 for gas or oil fired Steam Production Plants,
                      plus an amount included in Account 353 which represents the investment in step-up
                      transformers, circuit breakers, and switching equipment, etc. required to connect all
                      such units to the transmission system, less the accumulated provision for
                      depreciation for the gas or oil fired units in the Steam Production plants and the
                      accumulated provision for depreciation associated with the equipment included in
                      Account 353 described above, and less the proportionate amount of Account 282
                      Accumulated Deferred Income Taxes.
            I=        Preceding year insurance premium for Intermediate Generating Units included in RB
            PT =      Ad Valorem taxes for the preceding year for Intermediate Generating Units Included
                      in RB
            FT =      Applicable Corporation Franchise Tax for the preceding year for Intermediate
                      Generating Units included in RB



   Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                      Associate General Counsel

   Issued on:         November 21, 2008

   Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
   22, 2008.

2011 ETI Rate Case                                                                                        9-113
                                                                                                               Exhibit PJC-1
                                                                                                          2011 TX Rate Case
                                                                                                               Page 36 of 83




   Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 36
   Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
   Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
   Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
   Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
   Entergy Texas, Inc., Rate Schedule FERC No. 181

            OM = Operation and maintenance expenses plus the applicable general and administrative
                      expenses. These combined expenses will be determined annually by taking the
                      applicable accounts for each Company related to their owned generating capacity,
                      together with the applicable general and administrative expenses, proportioned to the
                      direct labor expenses.

            Fossil Fueled Units

                      Direct - Accounts 500, 502, 503, 504, 505, 506, 507, 510, 511, 512, 513 and 514.

                      Allocable - Accounts 920, 921, 922, 923, 924, 925, 926, 927, 928, 929, 930, 931 and
                             932.

            10.07 Adjustment for Tax Changes
            The Reserve Equalization Payment as determined above shall be adjusted to reflect the
   imposition of any applicable new taxes not included in the above formula, or for any increase or
   decrease in taxes included as of the date of this Agreement.


            10.08 Billing Procedure
            The billing parameters will be in effect from June 1 to the succeeding May 31 based on the
   preceding year's results.




   Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                      Associate General Counsel

   Issued on:         November 21, 2008

   Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
   22, 2008.

2011 ETI Rate Case                                                                                       9-114
                                                                                                               Exhibit PJC-1
                                                                                                          2011 TX Rate Case
                                                                                                               Page 37 of 83




  Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 37
  Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
  Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
  Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
  Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
  Entergy Texas, Inc., Rate Schedule FERC No. 181




           This Service Schedule MSS-1 shall be attached to and become a part of the Agreement dated
  the 23rd day of           April , 1982 and shall be effective with said Agreement or at such later date as
  may be fixed by any requisite regulatory approval or acceptance for filing.


  Attest                                                    ARKANSAS POWER & LIGHT COMPANY

  Original signed by                                                    Original signed by
  R.J. Estrada                                                          Jerry Maulden
  Assistant Secretary                                                   President



  Attest                                                    LOUISIANA POWER & LIGHT COMPANY


  Original signed by                                                    Original signed by
  W. H. Talbot                                                          J. M. Wyatt
  Secretary                                                             President



  Attest                                                    MISSISSIPPI POWER & LIGHT COMPANY


  Original signed by                                                    Original signed by
  R. J. Estrada                                                         D. C. Lutken
  Assistant Secretary                                                   President



  Attest                                                    NEW ORLEANS PUBLIC SERVICE INC.


  Original signed by                                                    Original signed by
  William C. Nelson                                                     James M. Cain
  Secretary                                                             President


  Issued by:         Kimberly Despeaux                                         Effective:        November 22, 2008
                     Associate General Counsel

  Issued on:         November 21, 2008

  Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
  22, 2008.

2011 ETI Rate Case                                                                                        9-115
                                                                                                               Exhibit PJC-1
                                                                                                          2011 TX Rate Case
                                                                                                               Page 38 of 83




   Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 38
   Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
   Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
   Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
   Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
   Entergy Texas, Inc., Rate Schedule FERC No. 181



                                            SERVICE SCHEDULE MSS-2
                                        TRANSMISSION EQUALIZATION
            20.01 Purpose
            The purpose of this Service Schedule is to provide the basis for equalizing among the
   Companies the ownership costs associated with Inter-Transmission Investment in such a manner
   that each Company will bear a portion of these costs proportional to its Responsibility Ratio.


            20.02 Inter-Transmission Investment
            A Company's Inter-Transmission Investment for the purpose of this schedule shall consist
   of:
            (a)       All of the investment in transmission lines operated at 230 kV or higher voltage to
                      the extent that such investment is not included in billings under other agreements.
            (b)       Investment in transmission substations with three or more lines operated at a
                      voltage of 230 kV or higher to the extent that such investment is not included in
                      billings under other agreements. Investment in such substations shall include
                      facilities down to but not including the high side disconnecting device of the
                      transformer, 50% of common facilities, and other facilities as approved by the
                      Operating Committee. Common substation facilities are those facilities not
                      directly associated with any of the major power supplying voltages of the
                      substation. They include but are not limited to land, roadway, lighting, control
                      house, fill, fencing, supervisory equipment, etc.
            (c)       All lines 115 kV and higher from the owning Company's last substation to the
                      connecting point of another Company (either Entergy System Company or nonsystem
                      Company) not included in (a), or not included in billings under other agreements.
            The investment in a generating unit step-up transformer and associated switchgear, necessary
   to connect the generating unit to the lines or all buses, shall not be included in subsection (b).



   Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                      Associate General Counsel

   Issued on:         November 21, 2008

   Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
   22, 2008.

2011 ETI Rate Case                                                                                        9-116
                                                                                                                 Exhibit PJC-1
                                                                                                            2011 TX Rate Case
                                                                                                                 Page 39 of 83



   Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 39
   Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
   Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
   Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
   Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
   Entergy Texas, Inc., Rate Schedule FERC No. 181

            In determining the investments above referred to under subsections (a) and (c), only those
   transmission line costs includable in Accounts 350, 352, 354, 355, 356, 357, 358 and 359 of the
   Federal Energy Regulatory Commission's Uniform System of Accounts Prescribed for Public Utilities
   and Licensees.
            The investments above referred to under subsection (b) are amounts includable in the accounts
   listed in the preceding paragraph plus Account 353.
            The investment in new transmission facilities included under this Service Schedule shall be
   added to a Company's Inter-Transmission Investment on the first day of the month following the "in
   service" date of the facilities. Each Company's Inter-Transmission Investment shall be revised as of
   the end of each month to adjust for any additions or retirements.


            20.03 Company Net Inter-Transmission Investment - Company Net Inter-Transmission
   Investment shall be the sum of the Company Inter-Transmission Investments reduced for the
   Accumulated Provision for Depreciation and Deferred Taxes as adjusted at each December 31.


            20.04 Transmission Responsibility - A Company's Transmission Responsibility shall be the
   sum of the System Net Inter-Transmission Investments multiplied by that Company's Responsibility
   Ratio.


            20.05 Transmission Equalization Payments - Each Company shall pay or receive each month,
   as appropriate, an amount in dollars determined by the following formula:
                      Dollars ($) = 1/12 (TR - TI) (AOC)
   where:
                      TR = The Company's Transmission Responsibility as defined in Section 20.04

                      TI = The Company's Net Inter-Transmission Investment as defined in Section 20.03

                      AOC = System Average Annual Ownership Cost




   Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                      Associate General Counsel

   Issued on:         November 21, 2008

   Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
   22, 2008.

2011 ETI Rate Case                                                                                         9-117
                                                                                                                 Exhibit PJC-1
                                                                                                            2011 TX Rate Case
                                                                                                                 Page 40 of 83



    Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 40
    Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
    Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
    Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
    Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
    Entergy Texas, Inc., Rate Schedule FERC No. 181

           20.06 Development of Company's Annual Ownership Cost - (AOCc) - The Annual Ownership
    Cost, expressed as a decimal, shall be determined as follows:

                 AOCc = (CM + F) +                  | D + I + PT + FT + OM                   |
                                                    |          K                             |
    where:
             CM = the weighted average cost of capital determined as
               follows:

             CM = (DR x i) + (PR x p) + (ER x c)
                       DR = Ratio of Debt Capital at Dec. 31 of the previous year
                       PR = Ratio of Preferred Stock at Dec. 31 of the previous year
                       ER = Ratio of Common Stock at Dec. 31 of the previous year
                       i = Average embedded cost of debt capital outstanding at Dec. 31 of the previous year
                       p = Average embedded cost of preferred stock outstanding at Dec. 31 of the previous
                              year
                       c = Return on common equity at 11.0%
             F = Federal and State Income Taxes as determined from the formulas:
                 F=      T x [CM - DR x i]
                       (1 - T)

             T = f + s - fs when federal tax is not deductible in computing state tax, and

                       T = f + s - 2fs when federal tax is deductible in
                               1 - fs
                         computing state tax, and

                       f = Federal Income Tax Rate

                       s = State Income Tax Rate weighted on prior year jurisdictional revenues if two or
                           more state jurisdictions are served

             K=        The ratio of a Company's Net Inter-Transmission Investment and Inter-
                       Transmission Investment (i.e., Section 20.03 ÷ Section 20.02)

             D=        Book depreciation as used by each Company expressed as a decimal of Inter-
                       Transmission Investment (Section 20.02).




    Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                       Associate General Counsel

    Issued on:         November 21, 2008

    Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
    22, 2008.

2011 ETI Rate Case                                                                                          9-118
                                                                                                                 Exhibit PJC-1
                                                                                                            2011 TX Rate Case
                                                                                                                 Page 41 of 83



   Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 41
   Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
   Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
   Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
   Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
   Entergy Texas, Inc., Rate Schedule FERC No. 181

            I=        Annual insurance cost expressed as a decimal of Inter-Transmission Investment
                      (Section 20.02).

            PT =      Average ad valorem taxes based on preceding year's tax rates and assessments for
                      the Inter-Transmission Investment expressed as a decimal of Inter-Transmission
                      Investment (Section 20.02).

            FT =      Corporate Franchise Tax based on preceding year's Inter-Transmission
                      Investment expressed as a decimal of Inter-Trans-mission Investment (Section
                      20.02).

            OM = Operating and maintenance expenses plus the applicable general and
                 administrative expenses expressed as a decimal of Inter-Transmission Investment
                 (Section 20.02). These combined expenses will be determined annually by taking
                 the applicable accounts for each Company, related to their total transmission
                 investment, together with the applicable general and administrative expenses and
                 proportioned to the direct labor expenses.

                      Direct - Accounts 560, 561, 562, 563, 564, 565, 566, 567, 568, 569, 570, 571, 572 and
                      573

                      Allocable - Accounts 920, 921, 922, 923, 924, 925, 926, 927, 928, 929, 930, 931 and
                      932

            20.07 Development of System Average Annual Ownership Cost
            The System Average Annual Ownership Cost to be applied to this Service Schedule shall
   be developed from the following formula:


   AOC = (A x AOCA)+(G x AOCG)+(L x AOCL)+(M x AOCM)+(N x AOCN) + (T x AOCT)
                         A+G+L+M+N+T

   where:
            AOC = System Average Annual Ownership Cost
                A = EAI Net Inter-Transmission Investment
                G = EGSL Net Inter-Transmission Investment
                L = ELL Net Inter-Transmission Investment




   Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                      Associate General Counsel

   Issued on:         November 21, 2008

   Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
   22, 2008.

2011 ETI Rate Case                                                                                         9-119
                                                                                                                 Exhibit PJC-1
                                                                                                            2011 TX Rate Case
                                                                                                                 Page 42 of 83



      Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 42
      Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
      Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
      Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
      Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
      Entergy Texas, Inc., Rate Schedule FERC No. 181

                   M = EMI Net Inter-Transmission Investment
                   N = ENOI Net Inter-Transmission Investment
                   T = ETI Net Inter-Transmission Investment
                   AOCA = EAI - Annual Ownership Cost
                   AOCG = EGSL - Annual Ownership Cost
                   AOCL = ELL - Annual Ownership Cost
                   AOCM = EMI - Annual Ownership Cost
                   AOCN = ENOI - Annual Ownership Cost
                   AOCT = ETI - Annual Ownership Cost


               20.08 Adjustment for Tax Changes
               The Transmission Equalization Payment as determined in Section 20.05 shall be adjusted
      to reflect the imposition of any applicable new taxes not included in the above formula, or for
      any increase or decrease in taxes included as of the date of this Agreement.


               20.09 Billing Procedure
               The billing parameters will be in effect from June 1 to the succeeding May 31, based on
      the preceding year's results.




      Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                         Associate General Counsel

      Issued on:         November 21, 2008

      Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
      22, 2008.

2011 ETI Rate Case                                                                                         9-120
                                                                                                                 Exhibit PJC-1
                                                                                                            2011 TX Rate Case
                                                                                                                 Page 43 of 83



    Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 43
    Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
    Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
    Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
    Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
    Entergy Texas, Inc., Rate Schedule FERC No. 181




             This Service Schedule MSS-2 shall be attached to and become a part of the Agreement dated
    the 23rd day of April, 1982 and shall be effective with said Agreement or at such later date as may
    be fixed by any requisite regulatory approval or acceptance for filing.


    Attest                                                   ARKANSAS POWER & LIGHT COMPANY



    Original signed by                                                    Original signed by
    R. J. Estrada                                                         Jerry Maulden
    Assistant Secretary                                                   President

    Attest                                                   LOUISIANA POWER & LIGHT COMPANY


    Original signed by                                                    Original signed by
    W. H. Talbott                                                         J. M. Wyatt
    Secretary                                                             President

    Attest                                                    MISSISSIPPI POWER & LIGHT COMPANY


    Original signed by                                                    Original signed by
    R. J. Estrada                                                         D. C. Lutken
    Assistant Secretary                                                   President

    Attest                                                    NEW ORLEANS PUBLIC SERVICE INC.


    Original signed by                                                    Original signed by
    William C. Nelson                                                     James M. Cain
    Secretary                                                             President




    Issued by:         Kimberly Despeaux                                         Effective:        November 22, 2008
                       Associate General Counsel

    Issued on:         November 21, 2008

    Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
    22, 2008.

2011 ETI Rate Case                                                                                          9-121
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 44 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 44
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181

                                              SERVICE SCHEDULE MSS-3
                    EXCHANGE OF ELECTRIC ENERGY AMONG THE COMPANIES

              30.01 Purpose
              The purpose of this Service Schedule is to provide the method of pricing energy
     exchanged among the Companies and to provide for payments and receipts in accordance with
     the provisions of Opinion Nos. 480 and 480-A.

              30.02 Scheduling of Energy Sources

              The System Capability shall be operated as scheduled and/or controlled by the System
     Operator to obtain the lowest reasonable cost of energy to all the Companies consistent with the
     requirements of daily operating generation reserve, voltage control, electrical stability, loading of
     facilities and continuity of service to the customers of each Company.
              In no event shall the remaining margin payment obligations of ETI to Southwestern
     Electric Power Corporation under Section 9.1 of the Restated and Amended Interconnection
     Agreement between ETI and Southwestern Electric Power Company, be included, considered or
     otherwise taken into account by the System Operator under Section 30.02 of the System
     Agreement, except for the circumstance where the lowest reasonable cost energy available to the
     System Operator is identical in price to that offered to ETI under such Section 9.1.

              30.03 Allocation of Energy

              The energy from the lowest cost source available and scheduled as in Section 30.02
     above shall be allocated on an hourly basis, in the order of the following priorities:
              (a)       first to the loads of the Company having such sources available, except that in the
              case of energy generated by a Designated Generating Unit, each Company to which a
              portion of the Capability of the Designated Generating Unit as defined in Section 40.02
              has been sold shall be entitled to receive each hour that portion of the total energy
              generated by the Designated Generating Unit that the capability sold to the Company
              bears to the total capability of the Designated Generating Unit.



     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                        9-122
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 45 of 83



    Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 45
    Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
    Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
    Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
    Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
    Entergy Texas, Inc., Rate Schedule FERC No. 181

             (b)       second to supply the requirements of the other Companies' Loads (Pool Energy).


             30.04 Energy for Sales to Others
             Energy used to supply others will be provided in accordance with rate schedules on file
    with the Federal Energy Regulatory Commission. A Company will be reimbursed for the
    current estimated cost of fuel used by the specific unit or units supplying the energy together
    with the adder determined in Section 30.08(f) on an hour by hour basis.


             30.05 Unscheduled Energy
             Energy produced by generating units not scheduled for system energy requirements but
    operated at the request of a Company beyond what is deemed necessary for overall system
    purposes by the System Operator, shall not be considered as part of Sections 30.03 or 30.04
    above, but shall be for the use, and at the expense of the Company requesting the operation of
    such generating units.


             30.06 Fuel Contract Energy
             Energy produced by generating units for system energy requirements shall be allocated as
    follows:
             (a)       When operated to satisfy "take or pay" minimums under fuel contracts negotiated
                       for System benefit as approved by the Operating Committee shall be shared by all
                       companies in proportion to their current Responsibility Ratio.
             (b)       When operated with fuel acquired for the benefit of two or more of the
                       Companies shall be shared in proportion to their participation in such contracts.
             (c)       When operated pursuant to fuel purchases negotiated for System benefit as approved
                       by the Operating Committee, the Company owning the units utilizing the fuel has a
                       one-time option to either assume responsibility for purchase of the fuel for its own
                       account or to allow the fuel to be purchased for the System's joint account in
                       accordance with 30.06(a) or (b) as appropriate.



    Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                       Associate General Counsel

    Issued on:         November 21, 2008

    Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
    22, 2008.

2011 ETI Rate Case                                                                                         9-123
                                                                                                                 Exhibit PJC-1
                                                                                                            2011 TX Rate Case
                                                                                                                 Page 46 of 83



   Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 46
   Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
   Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
   Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
   Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
   Entergy Texas, Inc., Rate Schedule FERC No. 181




            30.07 Cogeneration or Small Power Production Energy

            Energy received by any Company from Cogeneration or Small Power Production Sources that
   is included as a part of Inter-Company billings shall be priced under this Agreement in accordance
   with rates established by the appropriate regulatory authority. The Operating Committee shall have
   the authority to allocate such energy to one or more of the Companies or to determine that the energy
   is for the use, and at the expense of, the Company making the purchase from such Source in
   accordance with FERC Opinion Nos. 246 and 246-A.


            30.08 Payments to be Received for Energy Supplied
            Each Company shall receive, for energy furnished in accordance with Sections 30.03
   (a),(b) and 30.04 in excess of its load requirements, on an hourly basis:
            (a)       For each kWh generated as short term purchase energy from a Designated
                      Generating Unit in accordance with Section 30.03(a), whether or not taken by the
                      Company or Companies making the purchase, the cost of fuel consumed.
            (b)       For each kWh generated by use of fossil fuel, in accordance with Sections
                      30.03(b) and 30.04, the cost of fuel consumed plus an adder as determined in
                      Section 30.08 (f).
            (c)       For each kWh generated as Fuel Contract Energy, in accordance with Section
                      30.06, the cost of fuel consumed plus an adder as determined in Section 30.08(f).
            (d)       For purchased energy, the actual cost of such purchased energy. The "actual cost"
                      of purchased energy for ETI shall not include the remaining margin payment
                      obligation of ETI to Southwestern Electric Power Company, under Section 9.1 of
                      the Restated and Amended Interconnection Agreement between ETI and
                      Southwestern Electric Power Company.
            (e)       For each kWh received as Cogeneration or Small Power Production energy in
                      accordance with Section 30.07, the price established in Section 30.07.




   Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                      Associate General Counsel

   Issued on:         November 21, 2008

   Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
   22, 2008.

2011 ETI Rate Case                                                                                         9-124
                                                                                                         Exhibit PJC-1
                                                                                                    2011 TX Rate Case
                                                                                                         Page 47 of 83




  Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                   First Revised Sheet No. 47
  Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181          Superseding Original Sheet No. 47
  Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
  Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
  Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
  Entergy Texas, Inc., Rate Schedule FERC No. 181

           (f)       The adder for Sections 30.08(b) and 30.08(c) shall be determined pursuant to the
                     following formula.


               Adder = A + B + C
  where:
           A = .5563           O&M (current) ÷ NSGC
                                 O&M (base) ÷ NSGB                      where,

                     A=                 O&M adder in mills/kWh adjusted annually
                     O&M =              Accounts 500, 502, 503, 504, 505, 506, 507, 510, 511, 512, 513 and 514

                     Current =          Three years ending with preceding year
                     NSGC =             Net steam generation in kWh for the three years ending with preceding
                                        year

                     Base =             Three years of 1978, 1979 and 1980
                     NSGB =             Net steam generation in kWh for 1978, 1979 and 1980 base period

                     .5563 =       The amount applicable at the date of this agreement

                          ∴ O&M (base) ÷ NSGB = 1.6724




           B = AC x HR x (SR/2,000,000) where,
                     B=        Incremental replacement SO2 cost (in mills/kWh) for the particular generating
                               unit, adjusted weekly

                     AC = allowance cost (in $/allowance), adjusted weekly based on the average cost of
                          purchasing an emission allowance from an index accepted by FERC within a
                          test block approximately equal to the amount of emission allowances needed to
                          support wholesale transactions under this System Agreement and power sales
                          arrangements between the Companies and others.

                     HR = heat rate (in Btu/kWh)
                     SR = SO2 rate for fuel (in lb SO2/MMBtu)



  Issued by:         Kimberly Despeaux                                  Effective:        July 1, 2009
                     Associate General Counsel

  Issued on:         May 1, 2009

2011 ETI Rate Case                                                                                  9-125
                                                                                                      Exhibit PJC-1
                                                                                                 2011 TX Rate Case
                                                                                                      Page 48 of 83




      Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                    Original Sheet No. 47A
      Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
      Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
      Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
      Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
      Entergy Texas, Inc., Rate Schedule FERC No. 181


               C = NC x HR x (NR/2,000,000) where,

                         C=        incremental replacement NOx cost (in mills/kWh) for the particular
                                   generating unit, adjusted weekly

                         NC = allowance cost (in $/allowance), adjusted weekly based on the average
                              cost of purchasing a NOx emission allowance from an index accepted by
                              FERC within a test block approximately equal to the amount of emission
                              allowances needed to support wholesale transactions under this System
                              Agreement and power sales arrangements between the Companies and
                              others.

                         HR = heat rate (in Btu/kWh)

                         NR = NOx rate for fuel (in lb NOx/MMBtu)




      Issued by:         Kimberly Despeaux                                  Effective:     July 1, 2009
                         Associate General Counsel

      Issued on:         May 1, 2009

2011 ETI Rate Case                                                                              9-126
                                                                                                                 Exhibit PJC-1
                                                                                                            2011 TX Rate Case
                                                                                                                 Page 49 of 83



   Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 48
   Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
   Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
   Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
   Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
   Entergy Texas, Inc., Rate Schedule FERC No. 181




                30.09 Payments Made for Energy
            (a)       Each Company shall pay for energy allocated to it from a Designated Generating Unit
                      as purchased energy the cost of fuel consumed per kWh.
            (b)       Each Company shall pay for energy received from the energy allocated in accordance
                      with the provisions of Section 30.03(b) above, the weighted average cost per kWh of
                      energy, as provided under Section 30.08(b) above, accumulated and distributed on a
                      hourly basis.
            (c)       Each Company shall pay for energy received from the energy allocated in accordance
                      with the provisions of Section 30.06 above, the cost per kWh of energy as provided
                      under Section 30.08(c) above, accumulated and distributed on a hourly basis.
            (d)       Each Company shall pay or receive funds to the extent required to maintain Rough
                      Production Cost Equalization in accordance with the provisions of Sections 30.11
                      through 30.14 below.


            30.10 Cost of Fuel Per kWh
            Cost of fuel per kWh shall be determined for each generating unit by multiplying the BTU
   consumed per kWh of net generation during the preceding calendar year by the current estimated cost
   per BTU of the fuel used as furnished by each Company monthly. For the first year of operation of a
   new unit, BTU consumed per kWh of net generation shall be based on the design heat rate at 60% of
   full load capability at anticipated average annual back pressure.




   Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                      Associate General Counsel

   Issued on:         November 21, 2008

   Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
   22, 2008.

2011 ETI Rate Case                                                                                         9-127
                                                                                                                 Exhibit PJC-1
                                                                                                            2011 TX Rate Case
                                                                                                                 Page 50 of 83



    Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 49
    Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
    Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
    Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
    Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
    Entergy Texas, Inc., Rate Schedule FERC No. 181




             30.11 Rough Production Cost Equalization
             To maintain Rough Production Cost Equalization (RPCE) among the Companies, each
    Company’s actual Production Cost (PC) as determined in accordance with Section 30.12, shall be
    compared to its respective allocation of the System Average Production Cost (APC), as determined
    in accordance with Section 30.13, to determine if a Company’s PC deviates from its APC by more
    than +/-11%.
    where:
    Paying Company(ies) is a Company or Companies with a negative Disparity that could make
             payments under this provision;
    Receiving Company(ies) is a Company or Companies with a positive Disparity that could receive
             payments under this provision; and,
    Disparity (D) equals the ratio of PC to APC expressed in terms of the divergence from 100%
    D = (PC/APC - 1)* 100%

             (a)       If one or more Companies has a positive Disparity greater than eleven percent
                       (11%), but no Company(ies) has a negative Disparity greater than 11%, then a
                       payment shall be made by the Paying Company(ies) to the Receiving
                       Company(ies) such that the positive Disparity of any Receiving Company(ies)
                       after reflecting such payment is equal to 11% and the negative Disparity of any
                       Paying Company(ies) after reflecting such payment is no less than the negative
                       Disparity of any other Paying Company.
             (b)       If one or more Companies has a negative Disparity greater than 11%, but no
                       Company has a positive Disparity greater than 11%, then a payment shall be made
                       by the Paying Company(ies) to the Receiving Company(ies) such that after
                       reflecting such payment, any Paying Company(ies) has a negative Disparity equal
                       to 11% and that the positive Disparity of any Receiving Company(ies), after
                       reflecting such payment, is no less than another Receiving Company.




    Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                       Associate General Counsel

    Issued on:         November 21, 2008

    Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
    22, 2008.

2011 ETI Rate Case                                                                                         9-128
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 51 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 50
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181

              (c)       If one or more Receiving Companies has a positive Disparity greater than 11%
                        and one or more Companies has a negative Disparity greater than 11%, then a
                        payment shall be made by the Paying Company(ies) with a negative Disparity
                        greater than 11% to the Receiving Company(ies) with a positive Disparity greater
                        than 11% such that after reflecting such payments, all Receiving Company(ies)
                        will not have a Disparity exceeding 11% and the payment obligation shall be
                        distributed among Paying Companies such that no Company that will be making
                        payments has a negative Disparity after reflecting such payments less than that of
                        any other Paying Company. In the event that the payments made reduce the
                        positive Disparity of a Receiving Company(ies) to 11% but that one or more
                        Paying Companies has a negative Disparity after reflecting such payments that is
                        greater than 11%, then payments shall be made such that no Paying Company has
                        a negative Disparity that is greater than 11% and that the positive Disparity of any
                        Receiving Company, after reflecting such payments, is no less than another
                        Receiving Company.




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                        9-129
                                                                                                                 Exhibit PJC-1
                                                                                                            2011 TX Rate Case
                                                                                                                 Page 52 of 83



    Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 51
    Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
    Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
    Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
    Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
    Entergy Texas, Inc., Rate Schedule FERC No. 181

             30.12 Actual Production Cost
             The actual production cost (PC) is the sum of the actual variable production cost (VPC) and
    the actual fixed production cost (FPC) and shall be determined for each Company.1 The formula for
    developing the actual production cost is as follows:
             PC = VPC + FPC
             where:
                       VPC = Variable Production Cost
                           = VPRB * (CM + F) + VPX
                       where:
                                 VPRB = Variable Production Rate Base 2
                                      = NPP – NAD – (ADIT * NPPR)
                                        NPP = Nuclear Production Plant in Service as recorded in
                                                 FERC Plant Accounts 320 through 325 and FERC
                                                 Account 101.1 excluding Asset Retirement Obligations
                                                 (ARO) recorded in FERC Plant Account 326, if any
    1
      All Rate Base, Revenue and Expense items shall be based on the actual amounts on the
    Company’s books for the twelve months ended December 31 of the previous year as reported in
    FERC Form 1 or such other supporting data as may be appropriate for each Company; and shall
    include certain retail regulatory adjustments pursuant to the production cost methodology set
    forth in Exhibit ETR-26/ETR-28 filed in Docket No. EL01-88-001, including but not limited to:
    (1) the Deregulated Asset Plan adjustment for EGSL, (2) the regulated portion (70%) of River
    Bend for EGSL, (3) repricing of energy associated with the Vidalia purchase power contract for
    ELL based on the average annual Service Schedule MSS-3 rate paid by ELL, including the
    exclusion of the income tax savings of the Vidalia purchase power contract from ADIT and
    reflecting the reversal of the Vidalia capital transaction, and the debt rate associated with the
    Waterford 3 Sale/Leaseback for ELL, (4) exclusion of the EAI and EMI retail approved Grand
    Gulf Accelerated Recovery Tariff effects on purchased power on EAI’s and EMI’s production
    cost and (5) exclusion of any increased costs resulting from the amended Toledo Bend Power
    Sales Agreement accepted for filing in Docket No. ER07-984.
    2
      Rate Base values shall be based on the actual balances on the Company’s books as of
    December 31 of the previous year except for Fuel Inventory, Materials & Supplies and
    Prepayments which shall be based on the average of the beginning and ending actual balances on
    the Company’s books.




    Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                       Associate General Counsel

    Issued on:         November 21, 2008

    Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
    22, 2008.

2011 ETI Rate Case                                                                                         9-130
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 53 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 52
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181

                                              NAD = Nuclear Accumulated Provision for Depreciation and
                                                    Amortization excluding ARO associated with NPP
                                                    above, as recorded in FERC Accounts 108 and 111
                                                    (consistent with the accounting relating to Statement of
                                                    Financial Accounting Standards (SFAS) 143 approved
                                                    by the retail regulator having jurisdiction over the
                                                    Company, unless the FERC determines otherwise)
                                              ADIT = Net Accumulated Deferred Income Taxes (ADIT)
                                                     recorded in FERC Accounts 190, 281 and 282 (as
                                                     reduced by amounts not generally and properly
                                                     includable for FERC cost of service purposes, including
                                                     but not limited to, SFAS 109 ADIT amounts and ADIT
                                                     amounts arising from retail ratemaking decisions) plus
                                                     Accumulated Deferred Income Tax Credit-3% portion
                                                     only recorded in FERC Account 255
                                              NPPR = Ratio of Nuclear Production Plant excluding Waterford
                                                     3 Capital Lease to Total Plant excluding Intangible
                                                     Plant and Waterford 3 Capital Lease 3
                                                       = NPPXW3L / PXIW3L
                                              where:
                                                          NPPXW3L =           Nuclear Production Plant in Service
                                                                              excluding Waterford 3 Capital Lease
                                                                              as recorded in FERC Account 101.1
                                                          PXIW3L =            Electric Plant in Service which
                                                                              includes the sum of the Company’s
                                                                              Production, Transmission, Distribution
                                                                              and General Plant in Service recorded
                                                                              in FERC Plant Accounts 310 through
                                                                              399, Property under Capital Lease
                                                                              excluding Waterford 3 Capital Lease
                                                                              as recorded in FERC Account 101.1
                                                                              and Completed Construction not yet
                                                                              Classified as recorded in FERC
                                                                              Account 106 excluding ARO, if any

     3
      Plant ratios shall be determined based on plant in service balances exclusive of associated ARO
     as of December 31 of the previous year.




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                        9-131
                                                                                                                 Exhibit PJC-1
                                                                                                            2011 TX Rate Case
                                                                                                                 Page 54 of 83



   Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 53
   Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
   Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
   Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
   Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
   Entergy Texas, Inc., Rate Schedule FERC No. 181

                                CM = The weighted average cost of capital determined as follows:
                                   = (DR * i) + (PR * p) + (ER * c)
                                  where:
                                       DR =   Ratio of Debt Capital and Preferred Stock with tax
                                              deductible dividends (QUIPS) at Dec. 31 of the previous
                                              year
                                      PR =    Ratio of Preferred Stock without tax deductible dividends
                                              at Dec. 31 of the previous year
                                            ER =        Ratio of Common Stock at Dec. 31 of the previous year
                                            i=          Average embedded cost of debt capital and preferred stock
                                                        with tax deductible dividends (QUIPS) outstanding at Dec.
                                                        31 of the previous year
                                            p=          Average embedded cost of preferred stock outstanding at
                                                        Dec. 31 of the previous year
                                            c=          Simple average of the Companies’ approved retail return on
                                                        common equity rates at Dec. 31 of the previous year
                                F=          Federal and State Income Taxes determined from the following:

                                  =         T / (1-T) * (CM – DR * i)
                                where:
                                            T=          f + s - fs when federal tax is not deductible in computing
                                                        state tax, and
                                            T=          (f + s - 2fs) / 1 – (fs) when federal tax is deductible in
                                                        computing state tax, and
                                                        f=        Federal Income Tax Rate
                                                        s=        State Income Tax Rate

                                VPX = Variable Production Expense
                                       = NPOMNF + FE + PURP – RC + NDE
                                where:
                                            NPOMNF = Nuclear Production Operation and Maintenance
                                                     (O&M) Non-Fuel Expense, recorded in FERC
                                                     Accounts 517 through 532 excluding Nuclear Fuel
                                                     in FERC Account 518




   Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                      Associate General Counsel

   Issued on:         November 21, 2008

   Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
   22, 2008.

2011 ETI Rate Case                                                                                         9-132
                                                                                                             Exhibit PJC-1
                                                                                                        2011 TX Rate Case
                                                                                                             Page 55 of 83



    Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                       First Revised Sheet No. 54
    Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
    Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
    Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
    Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
    Entergy Texas, Inc., Rate Schedule FERC No. 181




                                             FE =             Production O&M Fuel Expense recorded in FERC
                                                              Accounts 501, 518 and 547
                                             PURP =           Purchased Power Expense recorded in FERC
                                                              Account 555, but excluding payments made
                                                              pursuant to Section 30.09(d) of this Service
                                                              Schedule and excluding the effects, debits and
                                                              credits, resulting from a regulatory decision that
                                                              causes the deferral of the recovery of current year
                                                              costs or the amortization of previously deferred
                                                              costs
                                             RC =             Revenue Credits resulting from revenue received
                                                              from customers outside the Company’s Net Area
                                                              for Production Service recorded in FERC Account
                                                              447, but excluding receipts received pursuant to
                                                              Section 30.09(d) of this Service Schedule
                                             NDE =            Nuclear Depreciation and Amortization Expense
                                                              associated with (NPP) as recorded in Accounts 403
                                                              and 404 and Decommissioning Expense, as
                                                              approved by Retail Regulators, unless the
                                                              jurisdiction for determining the depreciation and/or
                                                              decommissioning rate is vested in the FERC under
                                                              otherwise applicable law
                       FPC = Fixed Production Cost

                              = FPRB * (CM + F) + FPX – [(ITC / TX) * PPR]
                       where:
                                 FPRB = Fixed Production Rate Base

                                          = PPXN + CME – ADXN + FI - (ADIT * PPRXN) + [(GP – GAD +
                                            IP – IAA) * PLR] + (MS + P) * PPREG
                                 where:
                                             PPXN =           Production Plant in Service excluding Nuclear Plant
                                                              recorded in FERC Plant Accounts 310 through 317,
                                                              Accounts 330 through 346, and FERC Account
                                                              101.1 excluding ARO recorded in FERC Plant
                                                              Accounts 317 and 337, if any
                                             CME =            Coal Mining Equipment in FERC Plant Account
                                                              399 owned by the Company




    Issued by:         Kimberly Despeaux                                     Effective:         May 31, 2009
                       Associate General Counsel

    Issued on:         May 21, 2009

2011 ETI Rate Case                                                                                      9-133
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 56 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 55
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181

                                              ADXN =           Accumulated Provision for Depreciation and
                                                               Amortization associated with PPXN and CME
                                                               above, as recorded in FERC Accounts 108 and 111,
                                                               excluding ARO associated with PPXN and CME, if
                                                               any, (consistent with the accounting relating to
                                                               SFAS 143 approved by the retail regulator having
                                                               jurisdiction over the Company, unless the FERC
                                                               determines otherwise)
                                              FI =             Fuel Inventory recorded in FERC Account 151
                                              ADIT =           Net Accumulated Deferred Income Taxes plus
                                                               Accumulated Deferred Income Tax Credit
                                              PPRXN =          Ratio of Production Plant in Service excluding
                                                               Nuclear Plant to Total Plant excluding Intangible
                                                               Plant and Waterford 3 Capital Lease

                                                        =      PPXN / PXIW3L
                                              GP =             General Plant in Service recorded in FERC Plant
                                                               Accounts 389 through 398 excluding ARO, if any
                                              GAD =            General Plant Accumulated Provision for
                                                               Depreciation, as recorded in FERC Account 108
                                                               excluding ARO associated with GP above, if any,
                                                               (consistent with the accounting relating to SFAS
                                                               143 approved by the retail regulator having
                                                               jurisdiction over the Company, unless the FERC
                                                               determines otherwise)
                                              IP =             Intangible Plant in Service recorded in FERC Plant
                                                               Accounts 301 through 303
                                              IAA =            Intangible Plant Accumulated Provision for
                                                               Amortization associated with IP above recorded in
                                                               FERC Account 111




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                        9-134
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 57 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 56
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181




                                              PLR =            Ratio of Production Labor to Total Labor excluding
                                                               A&G Labor4
                                                 =             PL / LXAG
                                              where:
                                                               PL =   Production Labor charged to O&M
                                                                      Expense
                                                               LXAG = Total Labor charged to O&M Expense
                                                                      excluding A&G Labor
                                              MS =             Materials and Supplies recorded in FERC Account
                                                               154
                                              P=               Prepayments as recorded in FERC Account 165
                                              PPREG =          Ratio of Production Plant in Service to Electric and
                                                               Gas Plant in Service excluding Intangible Plant
                                                        =      PP / EGPXI
                                              where:
                                                               PP =         Production Plant in Service as recorded
                                                                            in FERC Plant Accounts 310 through
                                                                            346 and FERC Account 101.1 excluding
                                                                            ARO recorded in FERC Plant Accounts
                                                                            317, 326 and 337, if any
                                                               EGPXI = Electric and Gas Plant in Service defined
                                                                       as PXIW3L above plus Waterford 3
                                                                       Capital Lease as recorded in FERC
                                                                       Account 101.1 and Gas Plant as
                                                                       recorded in FERC Account 118
                                                                       excluding ARO, if any

     4
       Labor ratios shall be determined based on the payroll expense for each Operating Company,
     including those payroll expenses billed to it by EOI and ESI, for the twelve months ended
     December 31 of the previous year.




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                        9-135
                                                                                                                 Exhibit PJC-1
                                                                                                            2011 TX Rate Case
                                                                                                                 Page 58 of 83



   Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 57
   Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
   Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
   Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
   Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
   Entergy Texas, Inc., Rate Schedule FERC No. 181




                      FPX = Fixed Production Expense

                            = NFPOMXN + DEXN + [(AG + GDX + IAX) * PLR] + OT * PPR
                                where:
                                            NFPOMXN=Non-Fuel Production O&M Expense excluding
                                                    Nuclear; i.e. costs recorded in FERC Accounts 500
                                                    through 514 plus Accounts 535 through 554 plus
                                                    Account 556 less Accounts 501 and 547
                                            DEXN =           Depreciation and Amortization Expense associated with
                                                             the plant investment in PPXN as recorded in FERC
                                                             Accounts 403 and 404, as approved by Retail
                                                             Regulators unless the jurisdiction for determining the
                                                             depreciation rate is vested in the FERC under otherwise
                                                             applicable law.
                                            AG =             Administrative and General (A&G) O&M Expense
                                                             recorded in FERC Accounts 920 through 935
                                                             excluding Storm Accrual Expense recorded in
                                                             FERC Account 924
                                            GDX =            General Plant Depreciation Expense recorded in
                                                             FERC Account 403
                                            IAX =            Intangible Plant Amortization Expense recorded in
                                                             FERC Account 404
                                            OT =             Other Tax Expense recorded in FERC Account 408
                                            PPR =            Ratio of Production Plant to Total Plant excluding
                                                             Intangible Plant
                                                  =          PP / PXI
                                                             PXI =        Electric Plant in Service defined as
                                                                          PXIW3L above plus Waterford 3 Capital
                                                                          Lease as recorded in FERC Account
                                                                          101.1, excluding ARO, if any
                      ITC = Investment Tax Credit Amortization recorded in FERC Account 411
                      TX = Composite Corporate After Tax Income Tax Rate

                           = (1-T)




   Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                      Associate General Counsel

   Issued on:         November 21, 2008

   Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
   22, 2008.

2011 ETI Rate Case                                                                                         9-136
                                                                                                                 Exhibit PJC-1
                                                                                                            2011 TX Rate Case
                                                                                                                 Page 59 of 83



    Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 58
    Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
    Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
    Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
    Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
    Entergy Texas, Inc., Rate Schedule FERC No. 181




             30.13 Average Production Cost
             Each Company’s share of System Average Variable and Fixed Production Cost shall be
    determined based on its respective Annual Energy Ratio (Energy Ratio) and Load Responsibility
    Ratio (Demand Ratio), respectively. The formula for determining each Company’s share of System
    Average Production Cost is as follows:
             APC = Average Production Cost
                    = AVPC + AFPC
             where:
                       AVPC = Company’s Allocation of the System’s Variable Production
                              Cost
                                = SVPC * ER
                       where:
                                   SVPC = Sum of the Companies’ Actual Variable Production Cost

                                   ER =        Each Company’s Annual Energy (Net Area Requirements less
                                               Non-Requirements Sales for Resale defined as Total Disposition of
                                               Energy (FERC Form 1 Page 401a, Line 28) less Non-
                                               Requirements Sales for Resale (FERC Form 1 Page 401a, Line 24)
                                               less Net Transmission for Others (FERC Form 1 Page 401a, Line
                                               18)) Divided by the Sum of all Companies Annual Energy (Energy
                                               Ratio)
                       AFPC = Company’s Allocation of the System’s Fixed Production Cost
                                = SFPC * DR
                       where:
                                   SFPC = Sum of the Companies’ Actual Fixed Production Cost
                                   DR =        The ratio for each Company of its 12 CP loads divided by the sum
                                               of all Companies’ 12 CP loads as defined in Section 2.16(a)
                                               (Demand Ratio)




    Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                       Associate General Counsel

    Issued on:         November 21, 2008

    Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
    22, 2008.

2011 ETI Rate Case                                                                                          9-137
                                                                                                                 Exhibit PJC-1
                                                                                                            2011 TX Rate Case
                                                                                                                 Page 60 of 83



    Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 59
    Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
    Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
    Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
    Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
    Entergy Texas, Inc., Rate Schedule FERC No. 181




             30.14 Billing Procedure for Section 30.09(d)
             The billing parameters will be in effect from June 1 to the succeeding December 31 based on
    the preceding year’s results. Any amounts payable pursuant to Section 30.09(d) shall be paid on a
    monthly basis based on dividing the amount payable by seven. All amounts paid shall be recorded
    by each Company in FERC Account 555 – Purchased Power and all amounts received shall be
    recorded by each Company in FERC Account 447 – Sales for Resale. This billing procedure shall
    be effective June 1, 2007.




    Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                       Associate General Counsel

    Issued on:         November 21, 2008

    Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
    22, 2008.

2011 ETI Rate Case                                                                                         9-138
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 61 of 83



      Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 60
      Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
      Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
      Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
      Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
      Entergy Texas, Inc., Rate Schedule FERC No. 181




               This Service Schedule MSS-3 shall be attached to and become a part of the
      Agreement dated the 23rd day of                  April      , 1982 and shall be effective with said
      Agreement or at such later date as may be fixed by any requisite regulatory approval or
      acceptance for filing.


      Attest                                          ARKANSAS POWER & LIGHT COMPANY



      Original signed by                                                    Original signed by
      R. J. Estrada                                                         Jerry Maulden
      Assistant Secretary                                                   President



      Attest                                          LOUISIANA POWER & LIGHT COMPANY


      Original signed by                                                    Original signed by
      W. H. Talbot                                                          J. M. Wyatt
      Secretary                                                             President



      Attest                                          MISSISSIPPI POWER & LIGHT COMPANY
      Original signed by                                                    Original signed by
      R. J. Estrads                                                         D. C. Lutken
      Assistant Secretary                                                   President



      Attest                                          NEW ORLEANS PUBLIC SERVICE INC.


      Original signed by                                                    Original signed by
      William C. Nelson                                                     James M. Cain
      Secretary                                                             President




      Issued by:         Kimberly Despeaux                                         Effective:        November 22, 2008
                         Associate General Counsel

      Issued on:         November 21, 2008

      Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
      22, 2008.

2011 ETI Rate Case                                                                                        9-139
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 62 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 61
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181

                                              SERVICE SCHEDULE MSS-4
                                                UNIT POWER PURCHASE
              40.01 Purpose

                        The purpose of this Service Schedule is to provide the basis for making a unit
              power purchase between Companies and/or the sale of power purchased by another
              Company, unless an alternative basis is agreed to by the parties subject to the approval of
              the Commission and the regulatory agencies of the purchasing and selling Companies
              under otherwise applicable law and which provides a lower monthly capacity charge than
              the charge determined pursuant to Section 40.06 or Section 40.09 of this Service
              Schedule MSS-4.


              40.02 Designated Generating Unit
                        (a)       A Designated Generating Unit shall be any generating unit from which the
                                  unit power purchase is made under Section 40.01 that is mutually agreed
                                  upon by the purchaser and the seller.
                        (b)       Any Company that makes a Unit Power Purchase of a portion of capability
                                  shall be entitled to receive each hour, the same portion of the total energy
                                  generated by the Designated Generating Unit. Such energy shall be
                                  purchased at the cost of fuel consumed per kWh in accordance with
                                  Section 30.08(a) and will be treated in the same manner as any other
                                  energy available to the purchasing Company.


              40.03 Capability Payment
                        For the capability purchased in accordance with Section 40.02, the Company
              making the sale shall receive, from the Company making the purchase, a monthly
              payment determined in accordance with the method described in Section 40.06
              hereinafter.




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                         9-140
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 63 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 62
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181

                    The monthly capability payment to be received by a Company shall be determined
              by multiplying the kW of capability sold from its Designated Generating Unit by a charge
              per kW–month as defined below.


              40.04 Investment in Designated Generating Unit (DGURB)
                    For the purpose of calculating the Monthly Charge under Section 40.06, the
              investment in the Designated Generating Unit (based on the Federal Energy Regulatory
              Commission’s Uniform System of Accounts prescribed for the Public Utilities and
              Licensees) shall be:


                        DGURB = Designated Generating Unit Rate Base
                        DGURB = DGUPTPLT + DGUCME - DGUDR + DGUFINV - DGUADIT +
                                [(GPLT – GDR + IPLT – IAA) * (DGUL / LXAG)] + [(MS + PP) *
                                (DGUPLT / PLT)]

                        (a)       The cost of the Designated Generating Unit included in FERC Plant
                                  Accounts 310 through 346; the cost for step-up transformers, circuit
                                  breakers, switching equipment, etc. included in FERC Plant Account 353
                                  which are required to connect the Designated Generating Unit to the
                                  transmission system (DGUPTPLT),
                        (b)       Plus Coal Mining Equipment in FERC Plant Account 399 directly
                                  associated with the Designated Generating Unit (DGUCME),
                        (c)       Less the Accumulated Provision for Depreciation (consistent with the
                                  accounting relating to Statement of Financial Accounting Standards
                                  (SFAS) 143 approved by the retail regulator having jurisdiction over the
                                  Designated Generating Unit, unless the FERC determines otherwise)
                                  associated with items (a) and (b) above, as recorded in FERC Account
                                  108, excluding Nuclear Decommissioning Trust Fund Balances, if
                                  applicable (DGUDR),



     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                         9-141
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 64 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 63
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181

                        (d)       Plus Fuel Inventory for the Designated Generating Unit, if applicable, in
                                  FERC Accounts 151 and 152 (DGUFINV),
                        (e)       Less net Accumulated Deferred Income Taxes recorded in FERC
                                  Accounts 190, 281, 282 and 283 and Accumulated Deferred Investment
                                  Tax Credit – 3% portion only recorded in FERC Account 255
                                  (DGUADIT) directly associated with the Designated Generating Unit if
                                  known; otherwise, an allocation of the plant-related balances in FERC
                                  Accounts 190, 281, 282 and 283, as reduced by amounts not generally and
                                  properly includable for FERC cost of service purposes, including, but not
                                  limited to, SFAS 109 ADIT amounts and ADIT amounts arising from
                                  retail ratemaking decisions, and Accumulated Deferred Investment Tax
                                  Credit – 3% portion only recorded in FERC Account 255 based on the
                                  proportion of gross Plant in Service for the Designated Generating Unit
                                  (DGUPLT), where DGUPLT is the sum of the investment pursuant to
                                  Section 40.04 (a) above plus the calculated General and Intangible plant
                                  pursuant to Sections 40.04 (f) and (h) below, to the Company’s total gross
                                  Plant in Service (PLT), where PLT is the sum of Production,
                                  Transmission, Distribution, General and Intangible Plant in Service,
                        (f)       Plus an allocation of General Plant recorded in FERC Plant Accounts 389
                                  through 398 (GPLT) based on the proportion of labor for the Designated
                                  Generating Unit (DGUL) to the Company’s total Labor charged to O&M
                                  Expense excluding Administrative and General (“A&G”) Labor (LXAG),
                        (g)       Less an allocation of Accumulated Provision for Depreciation (consistent
                                  with the accounting relating to SFAS 143 approved by the retail regulator
                                  having jurisdiction over the Designated Generating Unit, unless the FERC
                                  determines otherwise) associated with item (f) above as recorded in FERC
                                  Account 108 (GDR) based on the proportion of labor for the Designated
                                  Generating Unit (DGUL) to the Company’s total Labor charged to O&M
                                  Expense excluding A&G Labor (LXAG),

     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                         9-142
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 65 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 64
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181

                        (h)       Plus an allocation of Miscellaneous Intangible Plant recorded in FERC
                                  Plant Account 303 (IPLT) based on the proportion of labor for the
                                  Designated Generating Unit (DGUL) to the Company's total Labor
                                  charged to O&M Expense excluding A&G Labor (LXAG),
                        (i)       Less an allocation of Accumulated Provision for Amortization associated
                                  with item (h) above recorded in FERC Account 111 (IAA) based on the
                                  proportion of labor for the Designated Generating Unit (DGUL) to the
                                  Company's total Labor charged to O&M Expense excluding A&G Labor
                                  (LXAG),
                        (j)       Plus an allocation of Materials & Supplies and Stores Expense
                                  Undistributed recorded in FERC Accounts 154 and 163, respectively,
                                  (MS) based on the proportion of Plant in Service for the Designated
                                  Generating Unit (DGUPLT) to the Company’s total Plant in Service
                                  (PLT), and
                        (k)       Plus an allocation of Prepayments recorded in FERC Account 165 (PP)
                                  based on the proportion of Plant in Service for the Designated Generating
                                  Unit (DGUPLT) to the Company’s total Plant in Service (PLT).


                        The Investment in the Designated Generating Unit (Designated Generating Unit
              Rate Base) shall be based on the actual balances on the seller’s books as of the end of the
              month immediately preceding the service month.


                        If the Designated Generating Unit is one of a multi-unit station, its costs shall
              include an allocation of the amounts in the above plant accounts, which are allocable to
              all the generating units in the station, such allocation to be in the ratio of the capability of
              the Designated Generating Unit to the total capability of all generating units installed in
              the station for the service month.




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                        9-143
                                                                                                                 Exhibit PJC-1
                                                                                                            2011 TX Rate Case
                                                                                                                 Page 66 of 83



    Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 65
    Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
    Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
    Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
    Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
    Entergy Texas, Inc., Rate Schedule FERC No. 181




             40.05 Expenses associated with Designated Generating Unit (OXP)
                       For the purpose of calculating the Monthly Charge under Section 40.06, expenses
             associated with Designated Generating Unit shall be the following:


                          OXP = Operating Expense
                          OXP = DGUPOM + [SEOM * (DGUSEPLT / SEPLT)] + DGUDE + DGUI +
                                DGUPT + DGUAG + [(GDX + OT + INDX) * (DGUL / LXAG)] + [FT *
                                (DGUPLT / PLT)]

                       (a)       The Designated Generating Unit Production Operation and Maintenance
                                 Expense (“O&M”) Expense, included in FERC Accounts 500 through 554
                                 excluding fuel in Accounts 501, 518 and 547 (DGUPOM),
                       (b)       Plus an allocation of O&M associated with Designated Generating Unit
                                 step-up transformers and related transmission investment recorded in
                                 FERC Accounts 562 and 570 (SEOM) based on the proportion of the
                                 Designated Generating Unit Step-up Transformer Plant recorded in Plant
                                 Account 353 (DGUSEPLT) to the Company’s total Transformer Station
                                 Equipment Plant recorded in Plant Account 353 (SEPLT),
                       (c)       Plus any Depreciation Expense associated with the plant investment in
                                 Designated Generating Unit referred to in Section 40.04 items (a) and (b)
                                 (as recorded in Account 403) and Decommissioning Expense, as approved
                                 by Retail Regulators, directly assigned to the Designated Generating Unit,
                                 if applicable (DGUDE) unless the jurisdiction for determining the
                                 depreciation and/or decommissioning rate is vested in the FERC under
                                 otherwise applicable law,
                       (d)       Plus Property Insurance Expense recorded in FERC Account 924 directly
                                 assigned to the Designated Generating Unit (DGUI),
                       (e)       Plus Ad Valorem Taxes recorded in FERC Account 408 directly assigned
                                 to the Designated Generating Unit (DGUPT),


    Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                       Associate General Counsel

    Issued on:         November 21, 2008

    Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
    22, 2008.

2011 ETI Rate Case                                                                                         9-144
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 67 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 66
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181

                        (f)       Plus A&G Expense (DGUAG) directly associated with a nuclear-fueled
                                  Designated Generating Unit recorded in FERC Accounts 920 through 935,
                                  excluding property insurance in Account 924; otherwise, an allocation of
                                  A&G Expense recorded in FERC Accounts 920 through 935 excluding
                                  property insurance in Account 924 based on the proportion of labor for the
                                  Designated Generating Unit (DGUL) to the Company’s total labor
                                  charged to O&M Expense excluding EOI and A&G labor,
                        (g)       Plus an allocation of General Plant Depreciation Expense recorded in
                                  FERC Account 403 (GDX) based on the proportion of labor for the
                                  Designated Generating Unit (DGUL) to the Company’s total Labor
                                  charged to O&M Expense excluding A&G Labor (LXAG),
                        (h)       Plus an allocation of Payroll Taxes recorded in FERC Account 408 (OT)
                                  based on the proportion of labor for the Designated Generating Unit
                                  (DGUL) to the Company’s total Labor charged to O&M Expense
                                  excluding A&G Labor (LXAG),
                        (i)       Plus an allocation of Miscellaneous Intangible Plant Amortization
                                  Expense recorded in FERC Account 404 (INDX) based on the proportion
                                  of labor for the Designated Generating Unit (DGUL) to the Company's
                                  total Labor charged to O&M Expense excluding A&G Labor (LXAG),
                                  and
                        (j)       Plus an allocation of Corporate Franchise Taxes recorded in FERC
                                  Account 408 (FT) based on the proportion of Plant in Service for the
                                  Designated Generating Unit (DGUPLT) to the Company’s total Plant in
                                  Service (PLT).


                        The expenses shall be based on transactions recorded on the seller's books for the
              service month.




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                        9-145
                                                                                                                  Exhibit PJC-1
                                                                                                             2011 TX Rate Case
                                                                                                                  Page 68 of 83



   Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 67
   Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
   Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
   Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
   Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
   Entergy Texas, Inc., Rate Schedule FERC No. 181

                      If the Designated Generating Unit is one of a multi-unit station, expenses relating
            to the common plant shall be allocated to the Designated Generating Units in the station
            based on the ratio of the capability of the Designated Generating Unit to the total
            capability of all generating units installed in the station for the service month.


            40.06 Determination of Monthly Capacity Charge
                      For the purpose of calculating the Monthly Capacity Charge (MC) per kW for
            billings under Capability Payment for each unit, the following formula shall be followed:
                                                  MONTHLY CAPACITY CHARGE

   MC =         Monthly Capacity Charge ($/kW-Month)

   MC =         [DGURB * ((CM + F)/12) + OXP - ITC/(1-T)] / CP
                Where:
                 DGURB = Designated Generating Unit Rate Base per Section 40.04

                      CM = The weighted average cost of capital consistent with the procedures used by each
                           Operating Company to calculate its AFUDC rate, determined as follows:

                      CM = (DR * i) + (PR * p) + (ER * c), where

                       DR = Ratio of Debt Capital and Preferred Stock with tax deductible dividends (QUIPS)
                             at the last day of the month immediately preceding the current service month
                       PR = Ratio of Preferred Stock without tax deductible dividends at the last day of the
                             month immediately preceding the current service month
                       ER = Ratio of Common Stock at the last day of the month immediately preceding the
                             current service month
                         i = Average embedded cost of debt capital outstanding at the last day of the month
                             immediately preceding the current service month
                        p = Average embedded cost of preferred stock outstanding at the last day of the
                             month immediately preceding the current service month
                        c = Return on common equity at 11.0%
                        F = Federal and State Income Tax as determined from the following:
                        F = T /(1 - T)* (CM – DR * i)

                     Where:




   Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                      Associate General Counsel

   Issued on:         November 21, 2008

   Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
   22, 2008.

2011 ETI Rate Case                                                                                          9-146
                                                                                                                  Exhibit PJC-1
                                                                                                             2011 TX Rate Case
                                                                                                                  Page 69 of 83



   Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 68
   Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
   Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
   Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
   Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
   Entergy Texas, Inc., Rate Schedule FERC No. 181



                                             T = f + s – fs when federal tax is not deductible in computing state tax,
                                                 and
                                             T = (f + s – 2fs) / (1-fs) when federal tax is deductible in computing
                                                 state tax, and
                                                           f = Federal Income Tax Rate
                                                           s = State Income Tax Rate

                     OXP = Operating Expense per Section 40.05
                      ITC = ITC Amortization recorded in FERC Account 411 directly associated with the
                            Designated Generating Unit if known; otherwise, an allocation of ITC
                            Amortization recorded in FERC Account 411 based on a gross plant-related
                            balance ratio
                       CP = Capability for the Designated Generating Unit as defined in Section 2.14 of the
                            Entergy System Agreement for the service month

            General Notes:
            (a)       Labor ratios shall be determined based on the sum of the payroll expenses for the
                      owner of the DGU, including those payroll expenses billed to it by EOI and ESI,
                      for the service month.
            (b)       Plant ratios shall be determined based on plant in service balances as of the end of
                      the month immediately preceding the service month.


            40.07 Adjustment for Tax Changes
                      The Capability Payment as determined above shall be adjusted to reflect the
            imposition of any applicable new taxes not included in the above formula or for any
            increase or decrease in taxes included as of the date of this Agreement.




   Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                      Associate General Counsel

   Issued on:         November 21, 2008

   Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
   22, 2008.

2011 ETI Rate Case                                                                                          9-147
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 70 of 83



     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 69
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181




              40.08 Billings Procedure
                        Bills for services rendered under Section 40.06 shall be issued within 45 days
              following the end of the service month and shall be payable within 10 days of receipt.
              Five days after such bill is due, interest shall accrue on any balance due at the rate as
              determined in Section 35.19a(2)iii of the FERC Regulations. The billing provisions
              under Section 4.14 of the Entergy System Agreement shall not apply to billings under
              Section 40.06 of this Service Schedule MSS-4.


              40.09 Designated Power Purchase
                        (a)       A Designated Power Purchase shall be any portion of a power purchase
                                  contract the sale and purchase of which is made pursuant to Section 40.01
                                  hereof, which is mutually agreed upon by the purchaser and the seller.
                                  Any resale of a power purchase from the Grand Gulf nuclear unit pursuant
                                  to Section 40.09 shall be subject to the approval of the Commission and
                                  the regulatory agency of the purchasing company.
                        (b)       Any Company that makes a Designated Power Purchase of a portion of the
                                  capability of the power purchase contract from which the sale and
                                  purchase is made shall be entitled to receive each hour, the same portion
                                  of the total energy purchased pursuant to the Designated Power Purchase
                                  subject to review by the FERC.
                        (c)       Sales to one Company of power purchased by another Company shall be
                                  priced at the delivered cost of said purchase incurred by the selling
                                  Company as recorded in FERC Accounts 555 and 565, excluding all
                                  timing effects on such costs due to retail ratemaking decisions on a
                                  monthly basis, and shall be billed pursuant to Section 4.14 of the Entergy
                                  System Agreement subject to review by the FERC.




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                         9-148
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 71 of 83



      Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 70
      Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
      Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
      Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
      Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
      Entergy Texas, Inc., Rate Schedule FERC No. 181

               This Service Schedule MSS-4 shall be attached to and become a part of the Agreement
      dated the 23rd day of                April      , 1982 and shall be effective with said Agreement or at
      such later date as may be fixed by any requisite regulatory approval or acceptance for filing.


      Attest                                          ARKANSAS POWER & LIGHT COMPANY



      Original signed by                                                    Original signed by
      R. J. Estrada                                                         Jerry Maulden
      Assistant Secretary                                                   President



      Attest                                          LOUISIANA POWER & LIGHT COMPANY


      Original signed by                                                    Original signed by
      W. H. Talbot                                                          J. M. Wyatt
      Secretary                                                             President



      Attest                                          MISSISSIPPI POWER & LIGHT COMPANY


      Original signed by                                                    Original signed by
      R. J. Estrada                                                         D. C. Lutken
      Assistant Secretary                                                   President



      Attest                                          NEW ORLEANS PUBLIC SERVICE INC.


      Original signed by                                                    Original signed by
      William C. Nelson                                                     James M. Cain
      Secretary                                                             President




      Issued by:         Kimberly Despeaux                                         Effective:        November 22, 2008
                         Associate General Counsel

      Issued on:         November 21, 2008

      Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
      22, 2008.

2011 ETI Rate Case                                                                                        9-149
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 72 of 83



      Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 71
      Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
      Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
      Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
      Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
      Entergy Texas, Inc., Rate Schedule FERC No. 181




                                              SERVICE SCHEDULE MSS-5

                            DISTRIBUTION OF REVENUE FROM SALES
                                MADE FOR THE JOINT ACCOUNT
                                   OF ALL THE COMPANIES
               50.01 Purpose

               The purpose of this Schedule is to provide a basis for the distribution among the
      Companies of the net balance received from sales to others for the joint account of all the
      Companies.


               50.02 Revenue Deductions
               From the gross revenue received for such sales there shall be deducted the cost of the
      sales determined by taking the sum of:
               (a)       Any direct tax imposed on the sale of capacity or energy or revenue derived
                         there from.
               (b)       Any appropriate adjustment for losses in the system of the Company providing
                         the connection.
               (c)       The cost of energy determined under the provisions of Section 30.04 of Service
                         Schedule MSS-3.
               (d)       The Ownership Costs for the specific connecting facilities not equalized
                         elsewhere. For this purpose, Ownership Costs shall be computed at the rate
                         developed for the connecting Company's Annual Ownership Cost under Service
                         Schedule MSS-2 on the facilities provided by the Company and approved by the
                         Operating Committee.




      Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                         Associate General Counsel

      Issued on:         November 21, 2008

      Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
      22, 2008.

2011 ETI Rate Case                                                                                        9-150
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 73 of 83



      Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 72
      Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
      Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
      Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
      Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
      Entergy Texas, Inc., Rate Schedule FERC No. 181




               50.03 Distribution of Net Balance
               The net balance remaining after the deductions provided for in 50.02 shall be
      distributed among the Companies in proportion to the Responsibility Ratio of each based on
      Sections 2.16(b) and 2.17(b). Provided, however, that EGSL and ETI shall not share in the
      distribution of the net revenue balance from sales to others for the joint account of all the
      Companies received from contracts entered by EAI, ELL, EMI, ENOI or Services prior to the
      merger. The net balance remaining after the deductions provided for in 50.02 for pre-merger
      sales shall be distributed among EAI, ELL, EMI and ENOI in proportion to the Company Load
      Responsibility of each divided by the sum of their Company Load Responsibilities based on
      Sections 2.16(b) and 2.17(b). EGSL and ETI shall participate pursuant to MSS-5 in any future
      sales, but shall only participate in the incremental portion of any extensions or expansions of
      existing contracts.




      Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                         Associate General Counsel

      Issued on:         November 21, 2008

      Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
      22, 2008.

2011 ETI Rate Case                                                                                        9-151
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 74 of 83



      Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 73
      Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
      Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
      Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
      Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
      Entergy Texas, Inc., Rate Schedule FERC No. 181




               This Service Schedule MSS-5 shall be attached to and become a part of the Agreement
      dated the 23rd day of             April     , 1982 and shall be effective with said Agreement or at
      such later date as may be fixed by any requisite regulatory approval or acceptance for filing.


      Attest                                          ARKANSAS POWER & LIGHT COMPANY



      Original signed by                                                    Original signed by
      R. J. Estrada                                                         Jerry Maulden
      Assistant Secretary                                                   President



      Attest                                          LOUISIANA POWER & LIGHT COMPANY


      Original signed by                                                    Original signed by
      W. H. Talbot                                                          J. M. Wyatt
      Secretary                                                             President



      Attest                                          MISSISSIPPI POWER & LIGHT COMPANY


      Original signed by                                                    Original signed by
      R. J. Estrada                                                         D. C. Lutken
      Assistant Secretary                                                   President



      Attest                                          NEW ORLEANS PUBLIC SERVICE INC.


      Original signed by                                                    Original signed by
      William C. Nelson                                                     James M. Cain
      Secretary                                                             President



      Issued by:         Kimberly Despeaux                                         Effective:        November 22, 2008
                         Associate General Counsel

      Issued on:         November 21, 2008

      Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
      22, 2008.

2011 ETI Rate Case                                                                                        9-152
                                                                                                                Exhibit PJC-1
                                                                                                           2011 TX Rate Case
                                                                                                                Page 75 of 83



      Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 74
      Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
      Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
      Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
      Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
      Entergy Texas, Inc., Rate Schedule FERC No. 181



                                              SERVICE SCHEDULE MSS-6

                               DISTRIBUTION OF OPERATING EXPENSES OF
                                     SYSTEM OPERATIONS CENTER

                60.01 Purpose
                The purpose of this Schedule is to provide a basis for the distribution among the
      Companies of the costs incurred by Services in providing and operating the System Operations
      Center.


                60.02 Costs
                Costs for the purpose of this Schedule shall include such items as salaries, wages,
      rentals, the cost of materials and supplies, interest, taxes, depreciation, transportation, travel
      expenses, consulting and other professional services, and other costs incurred by Services in
      providing, maintaining, and operating the System Operations Center in accordance with budget
      approved by the Operating Committee.


                60.03 Distribution of Costs
                All costs of the Center shall be paid by Services. All normal costs shall be billed by
      Services to the Companies in proportion to the Responsibility Ratio of each. However, if the
      System Operations Center makes a study or performs a service in which all Companies are not
      proportionately interested, any resulting cost shall be distributed to the interested parties in
      accordance with the standard procedures of Services as outlined in their application declaration
      as filed with the Securities and Exchange Commission.




      Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                         Associate General Counsel

      Issued on:         November 21, 2008

      Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
      22, 2008.

2011 ETI Rate Case                                                                                        9-153
                                                                                                                 Exhibit PJC-1
                                                                                                            2011 TX Rate Case
                                                                                                                 Page 76 of 83



   Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 75
   Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
   Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
   Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
   Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
   Entergy Texas, Inc., Rate Schedule FERC No. 181




            This Service Schedule MSS-6 shall be attached to and become a part of the Agreement dated
   the 23rd day of           April , 1982 and shall be effective with said Agreement or at such later date as
   may be fixed by any requisite regulatory approval or acceptance for filing.


   Attest                                          ARKANSAS POWER & LIGHT COMPANY



   Original signed by                                                    Original signed by
   R. J. Estrada                                                         Jerry Maulden
   Assistant Secretary                                                   President



   Attest                                          LOUISIANA POWER & LIGHT COMPANY


   Original signed by                                                    Original signed by
   W. H. Talbot                                                          J. M. Wyatt
   Secretary                                                             President



   Attest                                          MISSISSIPPI POWER & LIGHT COMPANY


   Original signed by                                                    Original signed by
   R. J. Estrada                                                         D. C. Lutken
   Assistant Secretary                                                   President



   Attest                                          NEW ORLEANS PUBLIC SERVICE INC.


   Original signed by                                                    Original signed by
   William C. Nelson                                                     James M. Cain
   Secretary                                                             President



   Issued by:         Kimberly Despeaux                                         Effective:        November 22, 2008
                      Associate General Counsel

   Issued on:         November 21, 2008

   Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
   22, 2008.

2011 ETI Rate Case                                                                                         9-154
                                                                                                              Exhibit PJC-1
                                                                                                         2011 TX Rate Case
                                                                                                              Page 77 of 83




     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 76
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181

                                          SERVICE SCHEDULE MSS-7

                             MERGER FUEL PROTECTION PROCEDURE

              70.01 Purpose
              This Service Schedule provides a procedure for protecting the participating
     Companies from incurring higher fuel and purchased power costs as a result of the merger
     with Gulf States. For a Company which incurs an increase in its fuel costs as a result of
     the merger, the increase in cost will be transferred back to the companies obtaining fuel
     savings in proportion to those savings, in accordance with the following provisions.


              70.02 Participating Companies
              Companies covered by this Service Schedule shall include Gulf States and any other
     Company notifying the Operating Committee prior to the first calculation performed
     pursuant to 70.03 of its intent to participate and that its participation has the approval of the
     regulatory agency with jurisdiction over the Company's retail rates. Any Company directed
     to participate by its retail regulator shall do so.


              70.03 Calculation Procedure of Fuel Cost Changes
              Each year after the effective date of the Entergy-Gulf States Merger (Merger),
     merger-related fuel cost changes (MRFC) will be Calculated for each Company in
     accordance with 70.05. The MRFC will be used to calculate a Cumulative Fuel Change
     Balance (CFCB) for each Company, as follows:

              Year ending CFCB = (Year beginning CFCB x (1 + i)) + MRFC)
                                  where: i = the average yield on ten-year U.S. Treasury Notes for
                                                the year just ended.




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                       9-155
                                                                                                              Exhibit PJC-1
                                                                                                         2011 TX Rate Case
                                                                                                              Page 78 of 83




     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 77
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181




              At the end of each of the years prior to the final year, if the CFCB is negative for
     one or more Companies and positive for one or more Companies, then 50 percent of the
     Company's positive CFCB (i.e., higher fuel costs due to the merger) shall be transferred to
     the CFCB of the Company or Companies with a negative balance. At the end of the tenth
     year (or such shorter period of time as set forth in Section 70.04) of this procedure, the
     above procedure will apply except that the full amount (100%) of a positive CFCB will be
     transferred subject to the limitation that such transfer does not cause the CFCB to become
     positive for another Company. For the Companies receiving the transferred amount, the
     transfer shall be allocated in proportion to each Company's percentage of the total of the
     negative balances of the participating companies.
              Any year after a positive amount is transferred from a Company's CFCB and that
     Company's CFCB subsequently becomes negative, then such previous transfers will be
     reversed to the extent the reversals do not cause the Company's CFCB to become positive.


              70.04 Limitation of Term
              This procedure shall apply for the shorter of: (1) the ten years following the
     effective date of the merger, or (2) the period between the effective date of the merger and
     the date of implementation of retail access in a jurisdiction in which one of the Companies
     operate.

              70.05 Fuel Cost Change Measurement Procedure
              Merger-related fuel cost changes (MRFC) for each Company are measured
     annually as the difference between estimated stand-alone fuel costs (SAFC) and estimated
     merger fuel costs (MFC), where:




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                       9-156
                                                                                                              Exhibit PJC-1
                                                                                                         2011 TX Rate Case
                                                                                                              Page 79 of 83




     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 78
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181



              SAFC =              The estimated annual cost of fuel and purchased energy incurred to
                                  serve the Company's net area dispatch, as determined by a
                                  simulation of the dispatch of generating units and system operations
                                  under stand-alone (non-combined) operation of the Gulf States and
                                  Entergy System (excluding Gulf States) using Entergy's most
                                  current delivery of the PROMOD III production cost model and the
                                  input assumptions set forth in 70.06.
              MFC =               The estimated annual cost of fuel and purchased energy incurred to
                                  serve a Company's net area requirements as determined by a
                                  simulation of the dispatch of generating units and system operations
                                  under merged operation (combined) of the system using Entergy's
                                  most current delivery of the PROMOD III production cost model
                                  and the input assumptions set forth in 70.06.

              70.06 Input Assumptions for Production Cost Simulations

              Customer Loads
              Actual hourly net area load, without off-system sales transactions, will be used as
     hourly load inputs.


              Resources
              The Gulf States and Entergy resources available to meet customer loads shall be
     those reflected in Entergy's most recent Business Plan applicable to that year.


              Generating Unit Efficiency
              The heat rate data shall be the then current data used in Entergy's Bulk Power
     Management system (BPMS).


              Generating Unit Availability
              Generating unit availability data (available MW's for each generating unit) shall be
     those reflected in the BPMS data for that time period.



     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                       9-157
                                                                                                              Exhibit PJC-1
                                                                                                         2011 TX Rate Case
                                                                                                              Page 80 of 83




     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 79
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181




              System Operating Constraints
              All generating unit constraints, fuel constraints, and transmission constraints as
     represented in Entergy's most current Business Plan applicable to that year will be
     reflected in the input assumptions. However, the transmission constraint known as Amite
     South shall be changed after the end of the fifth post merger year in the Entergy stand-
     alone analysis to that contained in the merger analysis for the remaining time period.


              Fuel Costs
     Nuclear            -- Actual monthly fuel cost as used in the Intra-System Billing (ISB)
                        program will be used as the nuclear fuel cost input.
     Coal               -- Actual monthly fuel cost as used in the ISB program will be used as the
                        coal fuel cost input except that the stand-alone fuel cost for North Antelope
                        coal shall be multiplied by the ratio of the stand-alone cost of North
                        Antelope coal to the merger cost of North Antelope coal for each Entergy
                        coal unit as reflected in 70.08.
      Gas/Oil            -- Fuel cost for each gas/oil unit will be based on actual weighted average
              fuel cost for each unit as calculated from fuel cost inputs to the ISB program.

              Off System Economy Purchases
              The simulations will reflect the off-system economy sources listed in 70.09. For
     the stand-alone simulations, these sources will be allocated to Gulf States and Entergy
     based on the most current year ending load responsibility ratios. The pricing of these
     transactions will be based on the actual monthly average on-peak and off-peak price of
     economy energy purchases, as determined by the ISB, plus a $2/MWH markup for each
     transaction for which Gulf States would require wheeling service from Entergy.




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                       9-158
                                                                                                              Exhibit PJC-1
                                                                                                         2011 TX Rate Case
                                                                                                              Page 81 of 83




     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 80
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181




              In addition, the Gulf States stand-alone simulation will also reflect a 300 MW off-
     peak source to be priced at the actual average monthly off-peak price of economy energy
     purchases as determined by the ISB. The available capacity for each Entergy stand-alone
     off-system economy source, as determined above, will be increased (to reflect economy
     energy not taken in the Gulf States stand-alone simulation) by the following method:

                  IMW =           Monthly on-peak and off-peak increase for each Entergy stand-
                                  alone off-system economy source rounded at the nearest whole
                                  MW.

                   =    AMW x (1-CF)

     where:

              AMW =               The available capacity (MW) for the off-system economy source in
                                  the Gulf States stand-alone.

              CF =                Monthly on-peak or off-peak capacity factor at which energy is
                                  taken in the Gulf States stand-alone simulation for the off-system
                                  economy source.

              Operating Reserves
              An operating reserve level of 6 percent of annual peak will be reflected in the input
     assumptions.


              70.07 PROMOD Benchmark
              A benchmark of PROMOD based on the actual 1992 and 1997 operating data will
     be made to verify the reasonableness of the model.




     Issued by:         Kimberly Despeaux                                        Effective:         November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                       9-159
                                                                                                               Exhibit PJC-1
                                                                                                          2011 TX Rate Case
                                                                                                               Page 82 of 83




     Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                               Original Sheet No. 81
     Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
     Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
     Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
     Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
     Entergy Texas, Inc., Rate Schedule FERC No. 181




              70.08 North Antelope Coal Prices
            The following ratios will be used to increase the actual North Antelope coal prices
     used in the stand-alone simulation case:

                        Year         Stand Alone                Combined
                                      ($/MMBtu)                 ($/MMBtu)                     Ratio
                         1994                  1.8261                      1.7910               1.0196
                         1995                  1.8997                      1.8500               1.0269
                         1996                  1.9423                      1.9190               1.0122
                         1997                  2.0918                      2.0240               1.0335
                         1998                  2.2096                      2.1760               1.0155
                         1999                  2.2556                      2.2160               1.0179
                         2000                  2.3466                      2.2960               1.0221
                         2001                  2.4274                      2.3800               1.0199
                         2002                  2.5114                      2.4830               1.0114
                         2003                  2.6041                      2.5690               1.0137


              70.09 Joint Dispatch Economy Purchase Capacities
        The following off-system economy resources will be used in the PROMOD simulations,
     with the figures below being capacity in MW:




     Issued by:         Kimberly Despeaux                                        Effective:           November 22, 2008
                        Associate General Counsel

     Issued on:         November 21, 2008

     Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
     22, 2008.

2011 ETI Rate Case                                                                                        9-160
                                                                                                                 Exhibit PJC-1
                                                                                                            2011 TX Rate Case
                                                                                                                 Page 83 of 83




      Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94                                  Original Sheet No. 82
      Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181
      Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69
      Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262
      Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8
      Entergy Texas, Inc., Rate Schedule FERC No. 181



     Company       Type of
                   Purchase        Month       1994    1995     1996    1997      1998   1999        2000   2001     2002      2003
      AECI         On Peak &       Year         400     400      400     400       400    400         400    400      400       400
                   Off Peak        Round
      Cajun        On Peak &       Jan.          200     200      200       200    200     200        200     200      200      200
                   Off Peak
      Cajun        On Peak &       Feb.          200     200      200       200    200     200        200     200      200      200
                   Off Peak
      Cajun        On Peak &       Mar.          200     200      200       200    200     200        200     200      200      200
                   Off Peak
      Cajun        On Peak &       Apr.          200     200      200       200    200     200        200     200      200      200
                   Off Peak
      Cajun        On Peak &       May           110      95       80       120    100     160        160     160      160      160
                   Off Peak
      Cajun        On Peak &       Jun.          110      95       80       120    100     160        160     160      160      160
                   Off Peak
      Cajun        On Peak &       Jul.          110      95       80       120    100     160        160     160      160      160
                   Off Peak
      Cajun        On Peak &       Aug.          110      95       80       120    100     160        160     160      160      160
                   Off Peak
      Cajun        On Peak &       Sep.          200     200      200       200    200     200        200     200      200      200
                   Off Peak
      Cajun        On Peak &       Oct.          200     200      200       200    200     200        200     200      200      200
                   Off Peak
      Cajun        On Peak &       Nov.          200     200      200       200    200     200        200     200      200      200
                   Off Peak
      Cajun        On Peak &       Dec.          200     200      200       200    200     200        200     200      200      200
                   Off Peak
     Empire        On Peak &       Year           50      50       50        50     50          50     50      50       50       50
                   Off Peak        Round
    Oklahoma       On Peak         Year          300     300      300       300    300     300        300     300      300      300
                   Only            Round
    Oklahoma       On Peak &       Year          250     150       60         0      0           0      0        0       0        0
                   Off Peak        Round
    Southern       On Peak &       Year           75      75       75        75     50          50     50      50       50       50
                   Off Peak        Round
     SWEPCO        On Peak &       Year          100     100      100       100    100     100        100     100      100      100
                   Off Peak        Round
     SWEPCO        On Peak         Year          200     200      200       200    200     200        200     200      200      200
                   Only            Round
       TVA         On Peak &       Year        1,00     1,00    1,00        750    500     500        500     500      500      500
                   Off Peak        Round          0        0       0
    Union EL       On Peak &       Year         400      400     400        400    400     400        400     400      400      400
                   Off Peak        Round




      Issued by:         Kimberly Despeaux                                         Effective:           November 22, 2008
                         Associate General Counsel

      Issued on:         November 21, 2008

      Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April
      22, 2008.

2011 ETI Rate Case                                                                                          9-161
    This page has been intentionally left blank.




2011 ETI Rate Case                       9-162
                                                                                                                   Exhibit PJC-2
                                                                                                              2011 TX Rate Case
                                                                                                                    Page 1 of 70




    Entergy Electric System                    Date range - 20100701 through 20100731                                                   Attachment 1
    Intra-System Billing-201007RA         KWH Log Sheet Reconciliation - Entergy Arkansas, Inc.                                               Page 1

                      Company               Net Gen       To Area           UPP         Exchange      Inadvertent    Firm Sales Sys Sales       Unacct

    AECC LOSS        IN                      2,995,170      2,995,170               0             0              0            0            0           0
    AECC PURCH LOSSES IN                       131,000        131,000               0             0              0            0            0           0
    AECC SALE LOSSES IN                        121,000        121,000               0             0              0            0            0           0
    AEP SERVICE CORP./MINDEN PAYBACK          (521,404)      (521,404)              0             0              0            0            0           0
    CALDWELL IMBAL IN                          269,838        269,838               0             0              0            0            0           0
    CALDWELL IMBAL OT                             (493)          (493)              0             0              0            0            0           0
    COG Sale Losses N                          189,395        189,395               0             0              0            0            0           0
    ETEC SALE LOSS N                           744,000        744,000               0             0              0            0            0           0
    GIS Imbalance IN                           258,860        258,860               0             0              0            0            0           0
    GIS Imbalance OT                          (269,531)      (269,531)              0             0              0            0            0           0
     PP Sale Losses N                        1,772,931      1,772,931               0             0              0            0            0           0
    JAS loss IN                                    418            418               0             0              0            0            0           0
    JBO LOSS        IN                       3,790,000      3,790,000               0             0              0            0            0           0
    K RBYV LLE IMBAL IN                        128,602        128,602               0             0              0            0            0           0
    K RBYV LLE IMBAL OT                         (1,332)        (1,332)              0             0              0            0            0           0
    NEWTON IMBAL IN                            206,611        206,611               0             0              0            0            0           0
    NEWTON IMBAL OT                               (130)          (130)              0             0              0            0            0           0
    SPA AECC PP IMBAL IN                     3,528,000      3,528,000               0             0              0            0            0           0
    SPA AECC PP IMBAL OT                    (5,902,000)    (5,902,000)              0             0              0            0            0           0
    SWPA/B/DG EXCHANG                      (28,495,000)   (28,495,000)              0             0              0            0            0           0
    ARK.NU 1                                86,421,339              0      86,421,339             0              0            0            0           0
    ARK.NU 1/NUCLEAR                       536,659,661    536,659,661               0             0              0            0            0           0
    ARK.NU 2                               102,307,792              0     102,307,792             0              0            0            0           0
    ARK.NU 2/NUCLEAR                       635,309,208    635,309,208               0             0              0            0            0           0
    BLAKLY 1/Aux                               (71,000)       (71,000)              0             0              0            0            0           0
    BLAKLY 1/HYDRO                          14,898,000     14,898,000               0             0              0            0            0           0
    BLAKLY 2/Aux                                (3,000)        (3,000)              0             0              0            0            0           0
    BLAKLY 2/HYDRO                           5,811,000      5,811,000               0             0              0            0            0           0
    CARPTR 1/Aux                              (110,000)      (110,000)              0             0              0            0            0           0
    CARPTR 1/HYDRO                           2,011,000      2,011,000               0             0              0            0            0           0
    CARPTR 2/Aux                               (12,000)       (12,000)              0             0              0            0            0           0
    CARPTR 2/HYDRO                           8,856,000      8,856,000               0             0              0            0            0           0
    COUCH 1/Aux                                (57,000)       (57,000)              0             0              0            0            0           0
    COUCH 2/CEGT E                          19,368,107      7,913,041               0     9,781,627      1,673,230            0            0         209
    COUCH 2/CENTERPO NT I                      168,893        129,859               0        17,362         21,672            0            0           0
    DEGRAY 1/HYDRO                           8,560,000      8,560,000               0             0              0            0            0           0
    DEGRAY 2/Aux                              (113,000)      (113,000)              0             0              0            0            0           0
    G.GULF 1/NUCLEAR                       201,820,133    201,820,133               0             0              0            0            0           0
    GGULF RET                               66,088,728              0      66,088,728             0              0            0            0           0
    GGULF RP                                32,499,259              0      32,499,259             0              0            0            0           0
     NDEPN 1                                24,696,343              0      24,696,343             0              0            0            0           0
    L.CATH 3/Aux                              (219,000)      (219,000)              0             0              0            0            0           0
    L.CATH 4/Aux                              (729,000)      (729,000)              0             0              0            0            0           0
    L.CATH 4/CEGT E                         22,337,765     14,391,650               0     7,839,611        105,794            0          710           0
    L.CATH 4/CENTERPOINT I                   3,592,235      2,174,843               0     1,399,984         17,408            0            0           0
    LYNCH 3/Aux                                (26,000)       (26,000)              0             0              0            0            0           0
    LYNCH 3/CEGT E                          10,201,913      7,109,876               0     2,936,490        154,920            0            0         627
    LYNCH 3/CENTERPOINT I                    2,144,087      1,475,204               0       659,947          8,936            0            0           0
    LYNCH IC/#2 OIL                              2,000              0               0         2,000              0            0            0           0
    MABELV T/CEGT E                          2,423,998      2,032,336               0         2,000        389,662            0            0           0
    MABELV T/CENTERPO NT I                   1,245,002      1,166,995               0             0         78,007            0            0           0
    OUACHITA 1/SIGCO I                      13,400,626     13,160,723               0       234,880          5,023            0            0           0
    OUACHITA 1/SIGPL E                      24,862,374     21,315,758               0     3,527,779         18,837            0            0           0
    OUACHITA 2/SIGCO I                       7,138,433      7,138,433               0             0              0            0            0           0
    OUACHITA 2/SIGPL E                      27,493,567     26,561,557               0       910,452         21,558            0            0           0
    REMMEL 1/HYDRO                           1,613,000      1,613,000               0             0              0            0            0           0
    REMMEL 2/HYDRO                           1,508,000      1,508,000               0             0              0            0            0           0
    REMMEL 3/Aux                               (13,000)       (13,000)              0             0              0            0            0           0
    REMMEL 3/HYDRO                           1,451,000      1,451,000               0             0              0            0            0           0
    RITCHE 1/Aux                               (28,000)       (28,000)              0             0              0            0            0           0
    WH.BLF 1                                45,314,539              0      45,314,539             0              0            0            0           0
    WH.BLF 2                                38,134,556              0      38,134,556             0              0            0            0           0
     NDEPN 1/COAL                          153,487,079    153,487,079               0             0              0            0            0           0
     NDEPN 2/COAL                                6,410          6,410               0             0              0            0            0           0
    WH.BLF 1/COAL                          281,394,779    255,052,371               0    25,833,205        509,203            0            0           0
    WH.BLF 2/Aux                               (10,260)       (10,260)              0             0              0            0            0           0
    WH.BLF 2/COAL                          236,808,729    234,500,243               0     2,103,620        204,866            0            0           0
    AECC Excess BAILEY 1                        50,110         19,387               0        30,723              0            0            0           0
    AECC Excess INDEPN 2                        14,445              0               0        14,445              0            0            0           0
    AECC Excess MCCLEL 1                     3,294,648      2,328,767               0       952,753         13,128            0            0           0
    AECC Excess WH.BLF 1                     1,487,454        562,317               0       914,776         10,361            0            0           0
    AECC Excess WH.BLF 2                     7,262,197      4,021,499               0     3,188,988         51,710            0            0           0
    CONWAY Excess WH.BLF 1                      49,300         49,300               0             0              0            0            0           0
    CONWAY Excess WH.BLF 2                     287,280        287,280               0             0              0            0            0           0
    ETEC Excess INDEPN 2                       166,582        166,582               0             0              0            0            0           0
    Attachment Snapshot: 20100826181933                          RunID: 17029                                              Billing Snapshot: 20100826175238

2011 ETI Rate Case                                                                                            9-163
                                                                                                                    Exhibit PJC-2
                                                                                                               2011 TX Rate Case
                                                                                                                     Page 2 of 70




 Entergy Electric System                     Date range - 20100701 through 20100731                                                 Attachment 1
 Intra-System Billing-201007RA          KWH Log Sheet Reconciliation - Entergy Arkansas, Inc.                                             Page 2

                   Company                Net Gen      To Area           UPP       Exchange      Inadvertent    Firm Sales Sys Sales        Unacct

 JONESBORO Excess INDEPN 2                 2,986,600     1,764,678             0     1,221,922              0             0           0            0
 JONESBORO Excess WH BLF 1                 4,868,500     3,114,865             0     1,744,400          9,235             0           0            0
 JONESBORO Excess WH BLF 2                 9,850,050     7,159,003             0     2,670,122         20,925             0           0            0
 OSCEOLA Excess INDEPN 1                     142,645       142,645             0             0              0             0           0            0
 OSCEOLA Excess INDEPN 2                   2,225,615     2,225,615             0             0              0             0           0            0
 WEST MEMPHIS Excess WH.BLF 1                 56,440        56,440             0             0              0             0           0            0
 WEST MEMPHIS Excess WH.BLF 2                454,030       454,030             0             0              0             0           0            0
 AECI/WSPP A                                 499,659       214,488             0       275,334          9,837             0           0            0
 AECI/WSPP B                               4,176,000     3,393,000             0       783,000              0             0           0            0
 AECI/WSPP C SYSTEM FIRM                   9,620,460     6,726,581             0     2,837,035         53,556             0       3,288            0
 AEP SERVICE CORP /WSPP A                    626,400       369,543             0       254,973          1,884             0           0            0
 AEP SERVICE CORP /WSPP C                    167,040       156,600             0        10,440              0             0           0            0
 AMEREN ENERGY NC. (AE) ACTING               501,120       353,129             0       145,951              0             0       2,040            0
 Ameren Energy Marketing Company/WSPP         10,440        10,440             0             0              0             0           0            0
 BNP PARIBAS ENERGY TRADING                   41,760        41,760             0             0              0             0           0            0
 BNP PARIBAS ENERGY TRADING                  803,671       770,263             0        33,408              0             0           0            0
 CALP NE ENERGY SERVICES L.P./WSPP         2,789,568     2,537,516             0       236,639              0             0      15,413            0
 CARGILL POWER MARKETS LLC/WSPP A            349,740       349,740             0             0              0             0           0            0
 CITIGROUP ENERGY NC/WSPP A                   50,112        39,672             0        10,440              0             0           0            0
 CLECO/WSPP B                              1,048,172       627,636             0       317,798         19,334             0      83,404            0
 CONSTELLATION ENERGY                         37,584        26,463             0             0         11,121             0           0            0
 CONSTELLATION ENERGY                      1,135,245       929,399             0       204,354            807             0         685            0
 COTTONWOOD ENERGY CO/EXS50                   41,619        34,000             0         7,619              0             0           0            0
 COTTONWOOD ENERGY CO/EXS75                   10,037         7,926             0         2,111              0             0           0            0
 COTTONWOOD ENERGY CO/EXS90                  438,669       386,586             0        51,457            626             0           0            0
 COTTONWOOD ENERGY CO/EXSSS50                  2,541         2,541             0             0              0             0           0            0
 COTTONWOOD ENERGY CO/EXSSTSH                290,367       209,453             0        80,914              0             0           0            0
 CROSS O L/QF                                209,394       132,508             0        76,886              0             0           0            0
 CYPRES/EXS50                                  3,999         3,999             0             0              0             0           0            0
 CYPRES/EXS75                                    219           219             0             0              0             0           0            0
 CYPRES/EXS90                                 26,430        26,430             0             0              0             0           0            0
 DB ENERGY TRAD NG LLC/WSPP B             21,593,680    18,492,782             0     2,901,191         87,866             0     111,632          209
 DUKE ENERGY HINDS/EXS50                      23,661        23,661             0             0              0             0           0            0
 DUKE ENERGY HINDS/EXS75                      17,266        11,684             0         5,582              0             0           0            0
 DUKE ENERGY HINDS/EXS90                     180,827       168,938             0        11,889              0             0           0            0
 DUKEENERGY HOTSPRING/EXS50                   29,273        29,253             0            20              0             0           0            0
 DUKEENERGY HOTSPRING/EXS75                   17,619        16,912             0           700              7             0           0            0
 DUKEENERGY HOTSPRING/EXS90                  152,741       150,477             0         2,264              0             0           0            0
 DUKEENERGY HOTSPRING/FREE                       156           156             0             0              0             0           0            0
 ENDURE ENERGY/WSPP A                        283,965       282,765             0             0              0             0       1,200            0
 ENDURE ENERGY/WSPP B                         13,572             0             0        13,572              0             0           0            0
 ETEC/WSPP B                                 244,298       244,298             0             0              0             0           0            0
 EXELON GENERATION COMPANY                19,524,239    15,079,121             0     4,361,740         52,602             0      30,776            0
 J ARON & COMPANY/WSPP B                   4,984,056     4,353,549             0       599,915         18,710             0      11,882            0
 J.P. MORGAN VENTURES ENERGY                  13,990        13,990             0             0              0             0           0            0
 J.P. MORGAN VENTURES ENERGY               1,019,989       900,488             0             0          3,268             0     116,233            0
 JBO/WSPP A                                2,019,305     1,537,630             0       217,449              0             0     264,226            0
 JBO/WSPP B                                2,168,386     1,840,823             0       275,382              0             0      52,181            0
 KANSAS CITY POWER & LIGHT                   300,881       300,881             0             0              0             0           0            0
 MAGNET COVE/EXS75                             3,545         3,545             0             0              0             0           0            0
 MAGNET COVE/EXS90                           164,007       128,342             0        35,561            104             0           0            0
 MAGNET COVE/EXSSTSH                         901,963       556,965             0       344,998              0             0           0            0
 MDEA CROSSROADS/EXS50                         4,846         4,846             0             0              0             0           0            0
 MDEA CROSSROADS/EXS75                           977           977             0             0              0             0           0            0
 MDEA CROSSROADS/EXS90                        34,261        34,261             0             0              0             0           0            0
 MERRILL LYNCH COMMODITIES                40,521,612    34,559,147             0     5,621,170        110,134             0     231,161            0
 MORGAN STANLEY/WSPP A                        51,366        29,859             0        21,507              0             0           0            0
 NRG POWER MARKETING LLC./WSPP A           6,217,020     3,363,918             0     2,773,777         79,325             0           0            0
 NRG POWER MARKETING LLC./WSPP B          38,603,785    33,443,893             0     4,613,037        159,901             0     386,954            0
 NRG POWER MARKETING LLC./WSPP C           1,740,348     1,515,609             0       212,817          5,681             0       6,241            0
 OCCIDENTAL POWER SERVICES/WSPP            1,189,742       859,931             0       241,196         23,113             0      65,502            0
 PINE BLUFF ENERGY/QF                     70,109,200    38,424,118             0    31,414,407        270,675             0           0            0
 RAINBOW ENERGY MARKETING                  2,907,333     2,746,765             0       154,939          5,629             0           0            0
 SMEPA/WSPP B                                626,400       601,514             0             0         19,675             0       5,211            0
 SOUTHERN COMPANY SERVICES INC.              114,840        52,200             0        62,640              0             0           0            0
 SOUTHERN COMPANY SERVICES INC.            2,213,280     1,811,139             0             0        120,558             0     281,583            0
 SUEZ Energy Marketing NA Inc./WSPP A      1,808,208     1,630,717             0       177,491              0             0           0            0
 SUEZ Energy Marketing NA Inc./WSPP B     11,804,928    10,673,972             0     1,049,490         18,284             0      63,182            0
 TEA/WSPP A                                  233,021       204,833             0        28,188              0             0           0            0
 TENASKA FRONTIER/EXS50                       17,152        17,152             0             0              0             0           0            0
 TENASKA FRONTIER/EXS75                       13,458         9,788             0         3,670              0             0           0            0
 TENASKA FRONTIER/EXS90                      218,226       177,130             0        40,595            501             0           0            0
 TENASKA/WSPP A                              490,888       484,557             0             0              0             0       6,331            0
 TENASKA/WSPP B                            4,812,638     4,317,828             0       449,719         14,162             0      30,929            0
 UNION POWER PARTNERS/WSPP A                  39,672        36,096             0         3,576              0             0           0            0
 Attachment Snapshot: 20100826181933                          RunID: 17029                                             Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                             9-164
                                                                                                                        Exhibit PJC-2
                                                                                                                   2011 TX Rate Case
                                                                                                                         Page 3 of 70




 Entergy Electric System                    Date range - 20100701 through 20100731                                                      Attachment 1
 Intra-System Billing-201007RA         KWH Log Sheet Reconciliation - Entergy Arkansas, Inc.                                                  Page 3

                   Company               Net Gen         To Area           UPP         Exchange      Inadvertent    Firm Sales Sys Sales        Unacct

 UNION POWER PARTNERS/WSPP B             34,397,079      30,983,289               0      3,127,518        145,624             0     140,230          418
 WESTAR ENERGY NC/WSPP A                  1,447,817       1,005,766               0        420,854         21,197             0           0            0
 WESTAR ENERGY NC/WSPP B                  6,170,038       4,937,510               0      1,228,584          1,632             0       2,312            0
 WESTAR ENERGY NC/WSPP C                    167,040         156,600               0         10,440              0             0           0            0
 WRIGHTSVILE POWER/EXS75                      7,745           7,745               0              0              0             0           0            0
 WRIGHTSVILE POWER/EXS90                    169,805         167,905               0          1,900              0             0           0            0
 YAZOO CITY/EXS90                             1,101           1,101               0              0              0             0           0            0
 Un-accounted In                              4,036           4,036               0              0              0             0           0            0
 Exchange                               131,563,443     131,547,746               0              0         13,186             0           0        2,511
 INADVERTENT N                            3,196,726       3,196,726               0              0              0             0           0            0

 Totals                                3,068,221,822   2,534,515,289     395,462,556   131,743,223      4,583,474             0   1,913,306        3,974




 Attachment Snapshot: 20100826181933                            RunID: 17029                                               Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                                 9-165
                                                                                                                       Exhibit PJC-2
                                                                                                                  2011 TX Rate Case
                                                                                                                        Page 4 of 70




 Entergy Electric System                     Date range - 20100701 through 20100731                                                    Attachment 1
 Intra-System Billing-201007RA         KWH Log Sheet Reconciliation - Entergy Louisiana, LLC                                                 Page 4

                   Company               Net Gen        To Area           UPP         Exchange      Inadvertent    Firm Sales Sys Sales        Unacct

 AEP SERVICE CORP /MINDEN PAYBACK           (625,318)      (625,318)              0             0              0             0            0           0
 BURAS TEMP                                  131,908              0               0        45,238              0             0       86,670           0
 CALDWELL IMBAL IN                           325,038        325,038               0             0              0             0            0           0
 CALDWELL IMBAL OT                              (592)          (592)              0             0              0             0            0           0
 COG Sale Losses N                           228,116        228,116               0             0              0             0            0           0
 EPI-ISES ELI    IN                       35,090,137     35,090,137               0             0              0             0            0           0
 GIS Imbalance IN                            311,804        311,804               0             0              0             0            0           0
 GIS Imbalance OT                           (323,377)      (323,377)              0             0              0             0            0           0
 IPP Sale Losses N                         2,135,618      2,135,618               0             0              0             0            0           0
 JAS loss N                                      503            503               0             0              0             0            0           0
 KIRBYVILLE IMBAL IN                         154,924        154,924               0             0              0             0            0           0
 KIRBYVILLE IMBAL OT                          (1,596)        (1,596)              0             0              0             0            0           0
 NEWTON IMBAL IN                             248,837        248,837               0             0              0             0            0           0
 NEWTON IMBAL OT                                (154)          (154)              0             0              0             0            0           0
 ACADIA POWER PARTNERS, LLC/WSPP          59,708,320              0      59,708,320             0              0             0            0           0
 ARK.NU 1/NUCLEAR                         24,991,859     24,991,859               0             0              0             0            0           0
 ARK.NU 2/NUCLEAR                         29,534,318     29,534,318               0             0              0             0            0           0
 G.GULF 1/NUCLEAR                        116,825,380    116,825,380               0             0              0             0            0           0
 GGULF RET                                19,691,908     19,691,908               0             0              0             0            0           0
 GGULF RP                                  9,494,456      9,494,456               0             0              0             0            0           0
 L.GPSY 1/BRDGLN E                         5,159,508      5,159,508               0             0              0             0            0           0
 L.GPSY 1/EVANG(LT) M                     42,028,954     33,569,285               0     7,913,583        545,584             0            0         502
 L.GPSY 1/EVG/CG I                         2,715,643      2,669,294               0        46,349              0             0            0           0
 L.GPSY 1/GSPL M                             815,895        815,895               0             0              0             0            0           0
 L.GPSY 2/Aux                               (575,000)      (575,000)              0             0              0             0            0           0
 L.GPSY 2/BRDGLN E                         2,381,479      1,275,111               0     1,045,351         61,017             0            0           0
 L.GPSY 2/CGT M                              441,540        402,937               0        25,995         12,608             0            0           0
 L.GPSY 2/EVANG(LT) M                     45,103,438     19,275,826               0    25,320,605        507,007             0            0           0
 L.GPSY 2/EVG/CG I                         3,083,544        898,936               0     2,135,948         48,660             0            0           0
 L.GPSY 2/GSPL M                           2,511,999      2,128,198               0       346,715         37,086             0            0           0
 L.GPSY 3/BRDGLN E                        56,921,780     56,920,943               0             0              0             0          837           0
 L.GPSY 3/CGT E                           18,834,369     18,834,369               0             0              0             0            0           0
 L.GPSY 3/CGT M                           56,529,560     56,529,560               0             0              0             0            0           0
 L.GPSY 3/EVANG(LT) M                     21,210,502     18,405,512               0     2,662,097        142,642             0            0         251
 L.GPSY 3/EVG/CG I                         4,340,255      4,340,255               0             0              0             0            0           0
 L.GPSY 3/GSPL E                           7,924,740      7,924,740               0             0              0             0            0           0
 L.GPSY 3/GSPL M                          30,570,794     30,570,794               0             0              0             0            0           0
 MURRAY 1/HYDRO                          110,159,000    110,159,000               0             0              0             0            0           0
 N NEMI 3/Aux                                (30,000)       (30,000)              0             0              0             0            0           0
 N NEMI 3/EVANG(LT) M                     13,804,559      7,722,572               0     5,982,602         99,385             0            0           0
 N NEMI 3/EVG/CG I                         1,470,441        515,670               0       905,754         49,017             0            0           0
 N NEMI 4/Aux                             (1,006,000)    (1,006,000)              0             0              0             0            0           0
 N NEMI 4/BRDGLN E                        18,726,728     18,726,728               0             0              0             0            0           0
 N NEMI 4/CGT E                            1,635,542      1,635,542               0             0              0             0            0           0
 N NEMI 4/CGT M                            4,245,923      4,245,923               0             0              0             0            0           0
 N NEMI 4/EVANG(LT) M                     62,673,146     59,118,809               0     3,228,244        323,984             0          603       1,506
 N NEMI 4/EVANG(SP) E                      3,730,147      3,730,147               0             0              0             0            0           0
 N NEMI 4/EVG/CG I                         7,083,201      7,081,977               0         1,224              0             0            0           0
 N NEMI 4/GSPL E                             446,596        446,596               0             0              0             0            0           0
 N NEMI 4/GSPL M                             803,482        803,482               0             0              0             0            0           0
 N NEMI 4/LGS E                            2,134,235      2,134,235               0             0              0             0            0           0
 N NEMI 5/Aux                               (141,000)      (141,000)              0             0              0             0            0           0
 N NEMI 5/BRDGLN E                        90,282,967     90,234,151               0             0              0             0       48,816           0
 N NEMI 5/CGT E                           26,968,843     26,968,843               0             0              0             0            0           0
 N NEMI 5/CGT M                           84,111,485     84,111,485               0             0              0             0            0           0
 N NEMI 5/EVANG(LT) M                     99,312,226     97,761,791               0     1,193,561        356,623             0            0         251
 N NEMI 5/EVANG(SP) E                        336,710        336,710               0             0              0             0            0           0
 N NEMI 5/EVG/CG I                         8,282,375      8,282,375               0             0              0             0            0           0
 N NEMI 5/GSPL E                           3,393,948      3,393,948               0             0              0             0            0           0
 N NEMI 5/GSPL M                           8,258,057      8,258,057               0             0              0             0            0           0
 N NEMI 5/LGS E                            5,155,389      5,155,389               0             0              0             0            0           0
 PERVIL 1                                194,914,500              0     194,914,500             0              0             0            0           0
 PERVIL 1/Aux                                (18,000)       (18,000)              0             0              0             0            0           0
 PERVIL 1/TENN E                          52,512,761     52,512,761               0             0              0             0            0           0
 PERVIL 1/TENN I                           5,888,462      5,888,462               0             0              0             0            0           0
 PERVIL 1/TEXAS GAS E                      6,570,277      6,570,277               0             0              0             0            0           0
 PERVIL 2/Aux                             (4,571,000)    (4,571,000)              0             0              0             0            0           0
 RVRBND 1/NUCLEAR                        139,555,800    139,555,800               0             0              0             0            0           0
 STERLN 6/Aux                               (213,000)      (213,000)              0             0              0             0            0           0
 TOLEDO 1/HYDRO                            2,246,500      2,246,500               0             0              0             0            0           0
 WATERF 1/Aux                                (62,000)       (62,000)              0             0              0             0            0           0
 WATERF 1/BRDGLN E                         2,728,053      1,820,443               0       843,299         64,311             0            0           0
 WATERF 1/CGT M                              613,149        254,658               0       356,988          1,503             0            0           0
 WATERF 1/EVANG(LT) M                     68,159,274     18,545,667               0    47,727,893      1,884,710             0            0       1,004
 WATERF 1/EVG/CG I                         4,491,524        789,096               0     3,677,054         25,374             0            0           0
 Attachment Snapshot: 20100826181933                           RunID: 17029                                               Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                                9-166
                                                                                                                     Exhibit PJC-2
                                                                                                                2011 TX Rate Case
                                                                                                                      Page 5 of 70




 Entergy Electric System                      Date range - 20100701 through 20100731                                                 Attachment 1
 Intra-System Billing-201007RA          KWH Log Sheet Reconciliation - Entergy Louisiana, LLC                                              Page 5

                   Company                Net Gen       To Area           UPP       Exchange      Inadvertent    Firm Sales Sys Sales        Unacct

 WATERF 2/#6 OIL                              352,500        50,000             0       302,500              0             0           0            0
 WATERF 2/BRDGLN E                         44,477,948    35,025,366             0     9,002,954        448,624             0           0        1,004
 WATERF 2/CGT E                            14,257,818    12,473,477             0     1,648,800        135,541             0           0            0
 WATERF 2/CGT M                            44,130,973    34,623,561             0     8,938,269        568,892             0           0          251
 WATERF 2/EVANG(LT) M                      11,514,423     8,153,222             0     3,286,637         74,564             0           0            0
 WATERF 2/EVG/CG I                          2,407,338     1,023,375             0     1,383,963              0             0           0            0
 WATERF 3/NUCLEAR                         866,024,000   866,024,000             0             0              0             0           0            0
 WATERF 4/#2 OIL                               46,000             0             0        46,000              0             0           0            0
 INDEPN 1/COAL                              7,145,175     7,145,175             0             0              0             0           0            0
 WH.BLF 1/COAL                             13,440,805    13,440,805             0             0              0             0           0            0
 WH.BLF 2/COAL                             10,706,289    10,706,289             0             0              0             0           0            0
 AECC Excess BAILEY 1                          60,190        60,190             0             0              0             0           0            0
 AECC Excess INDEPN 2                          17,399        17,399             0             0              0             0           0            0
 AECC Excess MCCLEL 1                       3,968,328     3,825,779             0       126,981         15,568             0           0            0
 AECC Excess WH.BLF 1                       1,791,648     1,791,648             0             0              0             0           0            0
 AECC Excess WH.BLF 2                       8,747,321     8,747,321             0             0              0             0           0            0
 ACADIA POWER PARTNERS, LLC/WSPP          119,416,680   119,351,055             0             0              0             0      65,625            0
 AECI/WSPP A                                  601,840       601,840             0             0              0             0           0            0
 AECI/WSPP B                                5,030,000     5,030,000             0             0              0             0           0            0
 AECI/WSPP C SYSTEM FIRM                   11,587,863    10,886,516             0       678,098         19,289             0       3,960            0
 AEP SERVICE CORP /WSPP A                     754,500       754,500             0             0              0             0           0            0
 AEP SERVICE CORP /WSPP C                     201,200       201,200             0             0              0             0           0            0
 AMEREN ENERGY NC. (AE) ACTING                603,600       601,142             0             0              0             0       2,458            0
 Ameren Energy Marketing Company/WSPP          12,575        12,575             0             0              0             0           0            0
 BNP PARIBAS ENERGY TRADING                    50,300        50,300             0             0              0             0           0            0
 BNP PARIBAS ENERGY TRADING                   968,024       968,024             0             0              0             0           0            0
 BP-ALLIANCE/QF                            12,189,947    12,189,947             0             0              0             0           0            0
 CALP NE ENERGY SERVICES L.P./WSPP          3,360,048     3,341,476             0             0              0             0      18,572            0
 CARGILL POWER MARKETS LLC/WSPP A             421,265       421,265             0             0              0             0           0            0
 CII CARBON CALCINER/QF                     7,833,120     7,833,120             0             0              0             0           0            0
 CITIGROUP ENERGY NC/WSPP A                    60,361        60,361             0             0              0             0           0            0
 CLECO/WSPP B                               1,262,618     1,027,846             0       132,197          2,103             0     100,472            0
 CONSTELLATION ENERGY                          45,271        45,271             0             0              0             0           0            0
 CONSTELLATION ENERGY                       1,367,406     1,366,580             0             0              0             0         826            0
 COTTONWOOD ENERGY CO/EXS50                    50,135        50,135             0             0              0             0           0            0
 COTTONWOOD ENERGY CO/EXS75                    12,102        12,102             0             0              0             0           0            0
 COTTONWOOD ENERGY CO/EXS90                   528,321       528,321             0             0              0             0           0            0
 COTTONWOOD ENERGY CO/EXSSS50                   3,060         3,060             0             0              0             0           0            0
 COTTONWOOD ENERGY CO/EXSSTSH                 349,743       349,743             0             0              0             0           0            0
 CYPRES/EXS50                                   4,816         4,816             0             0              0             0           0            0
 CYPRES/EXS75                                     264           264             0             0              0             0           0            0
 CYPRES/EXS90                                  31,833        31,833             0             0              0             0           0            0
 DB ENERGY TRAD NG LLC/WSPP B              26,009,688    25,875,218             0             0              0             0     134,470            0
 DUKE ENERGY HINDS/EXS50                       28,499        28,499             0             0              0             0           0            0
 DUKE ENERGY HINDS/EXS75                       20,807        20,807             0             0              0             0           0            0
 DUKE ENERGY HINDS/EXS90                      217,804       217,804             0             0              0             0           0            0
 DUKEENERGY HOTSPRING/EXS50                    35,260        35,260             0             0              0             0           0            0
 DUKEENERGY HOTSPRING/EXS75                    21,226        21,226             0             0              0             0           0            0
 DUKEENERGY HOTSPRING/EXS90                   183,983       183,983             0             0              0             0           0            0
 DUKEENERGY HOTSPRING/FREE                        189           189             0             0              0             0           0            0
 ENDURE ENERGY/WSPP A                         342,048       316,207             0        24,396              0             0       1,445            0
 ENDURE ENERGY/WSPP B                          16,348        16,348             0             0              0             0           0            0
 ETEC/WSPP B                                  294,260       294,260             0             0              0             0           0            0
 EXELON GENERATION COMPANY                 23,517,077    23,479,999             0             0              0             0      37,078            0
 GEORGIA GULF CORP/QF                       7,269,980     7,269,980             0             0              0             0           0            0
 J ARON & COMPANY/WSPP B                    6,003,359     5,862,580             0       126,465              0             0      14,314            0
 J.P. MORGAN VENTURES ENERGY                   16,851        16,851             0             0              0             0           0            0
 J.P. MORGAN VENTURES ENERGY                1,228,582     1,046,116             0        38,670          3,790             0     140,006            0
 JBO/WSPP A                                 2,432,270       834,360             0     1,258,817         20,805             0     318,288            0
 JBO/WSPP B                                 2,611,868     2,268,140             0       262,779         18,079             0      62,870            0
 KANSAS CITY POWER & LIGHT                    362,411       362,411             0             0              0             0           0            0
 MAGNET COVE/EXS75                              4,270         4,270             0             0              0             0           0            0
 MAGNET COVE/EXS90                            197,598       197,598             0             0              0             0           0            0
 MAGNET COVE/EXSSTSH                        1,086,406     1,086,406             0             0              0             0           0            0
 MDEA CROSSROADS/EXS50                          5,838         5,838             0             0              0             0           0            0
 MDEA CROSSROADS/EXS75                          1,178         1,178             0             0              0             0           0            0
 MDEA CROSSROADS/EXS90                         41,256        41,256             0             0              0             0           0            0
 MERRILL LYNCH COMMODITIES                 48,808,429    48,529,987             0             0              0             0     278,442            0
 MORGAN STANLEY/WSPP A                         61,868        61,868             0             0              0             0           0            0
 NRG POWER MARKETING LLC./WSPP A            7,488,413     7,111,163             0       377,250              0             0           0            0
 NRG POWER MARKETING LLC./WSPP B           46,498,600    45,526,626             0       500,863          5,000             0     466,111            0
 NRG POWER MARKETING LLC./WSPP C            2,096,255     2,063,587             0        25,150              0             0       7,518            0
 OCCIDENTAL CHEM CORP/QF                   48,338,250    48,338,250             0             0              0             0           0            0
 OCCIDENTAL POWER SERVICES/BASE           219,380,000   219,158,027             0             0              0             0     221,973            0
 OCCIDENTAL POWER SERVICES/DAY-            50,188,000    50,182,559             0             0              0             0       5,441            0
 Attachment Snapshot: 20100826181933                           RunID: 17029                                             Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                              9-167
                                                                                                                         Exhibit PJC-2
                                                                                                                    2011 TX Rate Case
                                                                                                                          Page 6 of 70




 Entergy Electric System                      Date range - 20100701 through 20100731                                                     Attachment 1
 Intra-System Billing-201007RA          KWH Log Sheet Reconciliation - Entergy Louisiana, LLC                                                  Page 6

                   Company                Net Gen         To Area           UPP         Exchange      Inadvertent    Firm Sales Sys Sales        Unacct

 OCCIDENTAL POWER SERVICES/ NTRA-           9,090,000      9,049,131               0              0              0             0      40,869             0
 OCCIDENTAL POWER SERVICES/WSPP             1,433,048      1,292,647               0         49,866         11,631             0      78,904             0
 RAINBOW ENERGY MARKETING                   3,501,908      3,501,908               0              0              0             0           0             0
 SMEPA/WSPP B                                 754,504              0               0        748,227              0             0       6,277             0
 SOUTHERN COMPANY SERVICES INC.               138,325        138,325               0              0              0             0           0             0
 SOUTHERN COMPANY SERVICES INC.             2,665,900              0               0      2,326,731              0             0     339,169             0
 SUEZ Energy Marketing NA Inc./WSPP A       2,178,009      2,178,009               0              0              0             0           0             0
 SUEZ Energy Marketing NA Inc./WSPP B      14,219,068     14,142,961               0              0              0             0      76,107             0
 TEA/WSPP A                                   280,677        280,677               0              0              0             0           0             0
 TENASKA FRONTIER/EXS50                        20,660         20,660               0              0              0             0           0             0
 TENASKA FRONTIER/EXS75                        16,210         16,210               0              0              0             0           0             0
 TENASKA FRONTIER/EXS90                       262,868        262,868               0              0              0             0           0             0
 TENASKA/WSPP A                               591,278        583,653               0              0              0             0       7,625             0
 TENASKA/WSPP B                             5,796,845      5,382,881               0        361,244         15,459             0      37,261             0
 UNION CARBIDE CORP/QF                     40,452,720     40,452,720               0              0              0             0           0             0
 UNION POWER PARTNERS/WSPP A                   47,786         47,786               0              0              0             0           0             0
 UNION POWER PARTNERS/WSPP B               41,431,444     41,262,525               0              0              0             0     168,919             0
 WESTAR ENERGY NC/WSPP A                    1,743,909      1,743,909               0              0              0             0           0             0
 WESTAR ENERGY NC/WSPP B                    7,431,833      7,429,047               0              0              0             0       2,786             0
 WESTAR ENERGY NC/WSPP C                      201,200        201,200               0              0              0             0           0             0
 WRIGHTSVILE POWER/EXS75                        9,333          9,333               0              0              0             0           0             0
 WRIGHTSVILE POWER/EXS90                      204,509        204,509               0              0              0             0           0             0
 YAZOO CITY/EXS90                               1,324          1,324               0              0              0             0           0             0
 Un-accounted In                                4,843          4,843               0              0              0             0           0             0
 Exchange                                  42,272,082     42,272,082               0              0              0             0           0             0
 INADVERTENT N                              3,850,516      3,850,516               0              0              0             0           0             0

 Totals                                 3,491,820,106   3,093,813,592     254,622,820   135,105,357      5,498,856             0   2,774,712        4,769




 Attachment Snapshot: 20100826181933                             RunID: 17029                                               Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                                  9-168
                                                                                                                     Exhibit PJC-2
                                                                                                                2011 TX Rate Case
                                                                                                                      Page 7 of 70




 Entergy Electric System                     Date range - 20100701 through 20100731                                                  Attachment 1
 Intra-System Billing-201007RA         KWH Log Sheet Reconciliation - Entergy Mississippi, Inc.                                            Page 7

                   Company                Net Gen       To Area           UPP       Exchange      Inadvertent    Firm Sales Sys Sales        Unacct

 AECCISES - MDEA                              37,000         37,000             0             0              0             0            0           0
 AECI - MDEA                               1,380,000      1,380,000             0             0              0             0            0           0
 AEP SERVICE CORP /MINDEN PAYBACK           (348,600)      (348,600)            0             0              0             0            0           0
 CALDWELL IMBAL IN                           180,158        180,158             0             0              0             0            0           0
 CALDWELL IMBAL OT                              (330)          (330)            0             0              0             0            0           0
 COG Sale Losses N                           126,412        126,412             0             0              0             0            0           0
 DOWCHEM - MDEA                              751,000        751,000             0             0              0             0            0           0
 EPMCNELSON6 - MDEA                        1,018,000      1,018,000             0             0              0             0            0           0
 GIS Imbalance IN                            172,809        172,809             0             0              0             0            0           0
 GIS Imbalance OT                           (180,160)      (180,160)            0             0              0             0            0           0
 HYDRO2 - MDEA                                18,000         18,000             0             0              0             0            0           0
 IPP Sale Losses N                         1,183,669      1,183,669             0             0              0             0            0           0
 JAS loss N                                      279            279             0             0              0             0            0           0
 JBOISES - MDEA                              302,000        302,000             0             0              0             0            0           0
 KIRBYVILLE IMBAL IN                          85,867         85,867             0             0              0             0            0           0
 KIRBYVILLE IMBAL OT                            (890)          (890)            0             0              0             0            0           0
 LAFA - MDEA                                  10,000         10,000             0             0              0             0            0           0
 LAGN - MDEA                              17,989,000     17,989,000             0             0              0             0            0           0
 MAGNETCOVE - MDEA                         1,322,000      1,322,000             0             0              0             0            0           0
 MDEA LOAD        OT                     (36,877,000)   (36,877,000)            0             0              0             0            0           0
 MEAM CANTON 1 IN                             73,000         64,137             0             0              0             0        8,863           0
 MEAM CANTON 2 IN                             83,000         74,000             0             0          1,000             0        8,000           0
 MEAM CANTON 3 IN                             84,000         75,000             0             0          1,000             0        8,000           0
 MEAM CANTON 4 IN                             84,000         75,000             0             0            989             0        8,011           0
 MEAM CANTON 5 IN                             82,000         70,378             0             0          1,622             0       10,000           0
 MEAM HENDERSON 10 IN                         58,000         51,751             0             0          1,249             0        5,000           0
 MEAM HENDERSON 11 IN                         59,000         47,450             0             0          3,550             0        8,000           0
 MEAM HENDERSON 2 IN                         524,000        412,807             0             0         42,277             0       68,916           0
 MEAM HENDERSON 4 IN                          72,000         49,000             0             0          9,142             0       13,858           0
 MEAM HENDERSON 5 IN                          72,000         48,810             0             0          9,024             0       14,166           0
 MEAM HENDERSON 6 IN                          73,000         45,124             0             0         12,876             0       15,000           0
 MEAM HENDERSON 7 IN                          76,000         43,120             0             0         13,721             0       19,159           0
 MEAM HENDERSON 8 IN                          74,000         37,250             0             0         12,000             0       24,750           0
 MEAM HENDERSON 9 IN                          54,000         25,257             0             0          5,521             0       23,222           0
 MEAM IMBALANCE IN                         4,082,291      4,082,291             0             0              0             0            0           0
 MEAM IMBALANCE OT                            (4,381)        (4,381)            0             0              0             0            0           0
 NEWTON IMBAL IN                             137,943        137,943             0             0              0             0            0           0
 NEWTON IMBAL OT                                 (86)           (86)            0             0              0             0            0           0
 PLUM - MDEA                                  31,000         31,000             0             0              0             0            0           0
 PPG - MDEA                                   28,000         28,000             0             0              0             0            0           0
 SABCOGEN - MDEA                             895,000        895,000             0             0              0             0            0           0
 SWPP - MDEA                              13,514,000     13,514,000             0             0              0             0            0           0
 TVA - MDEA                                  723,000        723,000             0             0              0             0            0           0
 ANDRUS 1/Aux                               (660,000)      (660,000)            0             0              0             0            0           0
 ANDRUS 1/TENN E                         155,006,673    152,213,418             0     2,659,523        106,471             0       27,261           0
 ANDRUS 1/TENN I                          16,394,504     15,647,456             0       716,204         30,499             0          345           0
 ANDRUS 1/TGT E                           69,484,823     68,929,469             0       500,938         54,416             0            0           0
 ARK.NU 1/NUCLEAR                         11,975,579     11,975,579             0             0              0             0            0           0
 ARK.NU 2/NUCLEAR                         14,206,469     14,206,469             0             0              0             0            0           0
 ATTALA 1/Aux                               (456,000)      (456,000)            0             0              0             0            0           0
 ATTALA 1/TETCO E                        158,162,196    158,162,196             0             0              0             0            0           0
 ATTALA 1/TETCO I                         20,360,804     20,360,804             0             0              0             0            0           0
 B.WLSN 1/COLUMBIA MAINLINE I                 80,752         80,752             0             0              0             0            0           0
 B.WLSN 1/COLUMBIA ML E                  129,355,248    129,305,896             0        38,457          9,513             0        1,382           0
 B.WLSN 2/COLUMBIA MAINLINE I              6,972,555      6,834,693             0       137,442              0             0            0         420
 B.WLSN 2/COLUMBIA ML E                  162,519,445    140,255,044             0    21,706,585        548,970             0        8,426         420
 DELTA5 1/Aux                                (35,000)       (35,000)            0             0              0             0            0           0
 DELTA5 2/Aux                                (42,000)       (42,000)            0             0              0             0            0           0
 G.GULF 1/NUCLEAR                        275,374,110    275,374,110             0             0              0             0            0           0
 GGULF RET                                 8,775,642      8,775,642             0             0              0             0            0           0
 GGULF RP                                  4,440,083      4,440,083             0             0              0             0            0           0
 REX BR 1/Aux                                (76,000)       (76,000)            0             0              0             0            0           0
 REX BR 3/Aux                                (73,000)       (73,000)            0             0              0             0            0           0
 REX BR 4/GSPL E                          20,874,591     13,534,553             0     5,393,054      1,946,844             0            0         140
 REX BR 4/GSPL I                           1,463,409      1,163,408             0       201,384         98,617             0            0           0
 REX BR 5/#2 O L                               5,000          2,580             0             0          2,420             0            0           0
 REX BR 5/Aux                                 (3,000)        (3,000)            0             0              0             0            0           0
 INDEPN 1/COAL                           144,835,585    144,835,585             0             0              0             0            0           0
 INDEPN 2/Aux                               (199,500)      (199,500)            0             0              0             0            0           0
 INDEPN 2/COAL                           120,547,500    120,547,500             0             0              0             0            0           0
 WH.BLF 1/COAL                             6,292,389      6,292,389             0             0              0             0            0           0
 WH.BLF 2/COAL                             5,295,338      5,295,338             0             0              0             0            0           0
 AECC Excess BAILEY 1                         33,336         32,919             0           417              0             0            0           0
 AECC Excess INDEPN 2                          9,643          9,643             0             0              0             0            0           0
 AECC Excess MCCLEL 1                      2,199,527      2,084,823             0       114,704              0             0            0           0
 Attachment Snapshot: 20100826181933                           RunID: 17029                                             Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                              9-169
                                                                                                                      Exhibit PJC-2
                                                                                                                 2011 TX Rate Case
                                                                                                                       Page 8 of 70




 Entergy Electric System                      Date range - 20100701 through 20100731                                                  Attachment 1
 Intra-System Billing-201007RA          KWH Log Sheet Reconciliation - Entergy Mississippi, Inc.                                            Page 8

                   Company                 Net Gen      To Area           UPP       Exchange       Inadvertent    Firm Sales Sys Sales        Unacct

 AECC Excess WH.BLF 1                         993,060       993,060             0            0                0             0           0            0
 AECC Excess WH.BLF 2                       4,848,407     4,848,407             0            0                0             0           0            0
 AECI/WSPP A                                  333,584       333,584             0            0                0             0           0            0
 AECI/WSPP B                                2,788,000     2,788,000             0            0                0             0           0            0
 AECI/WSPP C SYSTEM FIRM                    6,422,855     6,420,661             0            0                0             0       2,194            0
 AEP SERVICE CORP /WSPP A                     418,200       418,200             0            0                0             0           0            0
 AEP SERVICE CORP /WSPP C                     111,520       111,520             0            0                0             0           0            0
 AMEREN ENERGY NC. (AE) ACTING                334,560       333,199             0            0                0             0       1,361            0
 Ameren Energy Marketing Company/WSPP           6,970         6,970             0            0                0             0           0            0
 BNP PARIBAS ENERGY TRADING                    27,880        27,880             0            0                0             0           0            0
 BNP PARIBAS ENERGY TRADING                   536,551       536,551             0            0                0             0           0            0
 CALP NE ENERGY SERVICES L.P./WSPP          1,862,384     1,852,091             0            0                0             0      10,293            0
 CARGILL POWER MARKETS LLC/WSPP A             233,494       233,494             0            0                0             0           0            0
 CITIGROUP ENERGY NC/WSPP A                    33,456        33,456             0            0                0             0           0            0
 CLECO/WSPP B                                 699,790       543,971             0       97,617            2,518             0      55,684            0
 CONSTELLATION ENERGY                          25,092        25,092             0            0                0             0           0            0
 CONSTELLATION ENERGY                         757,918       757,460             0            0                0             0         458            0
 COTTONWOOD ENERGY CO/EXS50                    27,787        27,787             0            0                0             0           0            0
 COTTONWOOD ENERGY CO/EXS75                     6,703         6,703             0            0                0             0           0            0
 COTTONWOOD ENERGY CO/EXS90                   292,830       292,830             0            0                0             0           0            0
 COTTONWOOD ENERGY CO/EXSSS50                   1,696         1,696             0            0                0             0           0            0
 COTTONWOOD ENERGY CO/EXSSTSH                 193,858       193,858             0            0                0             0           0            0
 CYPRES/EXS50                                   2,669         2,669             0            0                0             0           0            0
 CYPRES/EXS75                                     146           146             0            0                0             0           0            0
 CYPRES/EXS90                                  17,648        17,648             0            0                0             0           0            0
 DB ENERGY TRAD NG LLC/WSPP B              14,416,465    14,341,940             0            0                0             0      74,525            0
 DUKE ENERGY HINDS/EXS50                       15,797        15,797             0            0                0             0           0            0
 DUKE ENERGY HINDS/EXS75                       11,523        11,523             0            0                0             0           0            0
 DUKE ENERGY HINDS/EXS90                      120,648       120,648             0            0                0             0           0            0
 DUKEENERGY HOTSPRING/EXS50                    19,538        19,538             0            0                0             0           0            0
 DUKEENERGY HOTSPRING/EXS75                    11,762        11,762             0            0                0             0           0            0
 DUKEENERGY HOTSPRING/EXS90                   101,969       101,969             0            0                0             0           0            0
 DUKEENERGY HOTSPRING/FREE                        105           105             0            0                0             0           0            0
 ENDURE ENERGY/WSPP A                         189,589       188,788             0            0                0             0         801            0
 ENDURE ENERGY/WSPP B                           9,061         9,061             0            0                0             0           0            0
 ETEC/WSPP B                                  163,098       163,098             0            0                0             0           0            0
 EXELON GENERATION COMPANY                 13,034,879    13,014,333             0            0                0             0      20,546            0
 J ARON & COMPANY/WSPP B                    3,327,478     3,203,622             0       83,328           32,597             0       7,931            0
 J.P. MORGAN VENTURES ENERGY                    9,340         9,340             0            0                0             0           0            0
 J.P. MORGAN VENTURES ENERGY                  680,969       603,370             0            0                0             0      77,599            0
 JBO/WSPP A                                 1,348,137     1,148,057             0       23,631               43             0     176,406            0
 JBO/WSPP B                                 1,447,671     1,322,239             0       90,177                0             0      34,835          420
 KANSAS CITY POWER & LIGHT                    200,875       200,875             0            0                0             0           0            0
 MAGNET COVE/EXS75                              2,366         2,366             0            0                0             0           0            0
 MAGNET COVE/EXS90                            109,555       109,555             0            0                0             0           0            0
 MAGNET COVE/EXSSTSH                          602,169       602,169             0            0                0             0           0            0
 MDEA CROSSROADS/EXS50                          3,235         3,235             0            0                0             0           0            0
 MDEA CROSSROADS/EXS75                            653           653             0            0                0             0           0            0
 MDEA CROSSROADS/EXS90                         22,867        22,867             0            0                0             0           0            0
 MERRILL LYNCH COMMODITIES                 27,053,226    26,898,900             0            0                0             0     154,326            0
 MISS CHEM NITROGEN/QF                         29,448        29,448             0            0                0             0           0            0
 MORGAN STANLEY/WSPP A                         34,292        34,292             0            0                0             0           0            0
 NRG POWER MARKETING LLC./WSPP A            4,150,635     4,150,635             0            0                0             0           0            0
 NRG POWER MARKETING LLC./WSPP B           25,772,818    25,421,212             0       57,038           36,234             0     258,334            0
 NRG POWER MARKETING LLC./WSPP C            1,161,899     1,157,732             0            0                0             0       4,167            0
 OCCIDENTAL POWER SERVICES/WSPP               794,302       695,710             0       54,861                0             0      43,731            0
 RAINBOW ENERGY MARKETING                   1,941,010     1,941,010             0            0                0             0           0            0
 SMEPA/WSPP B                                 418,200       414,721             0            0                0             0       3,479            0
 SOUTHERN COMPANY SERVICES INC.                76,670        76,670             0            0                0             0           0            0
 SOUTHERN COMPANY SERVICES INC.             1,477,640     1,209,063             0            0           80,583             0     187,994            0
 SUEZ Energy Marketing NA Inc./WSPP A       1,207,204     1,207,204             0            0                0             0           0            0
 SUEZ Energy Marketing NA Inc./WSPP B       7,881,251     7,839,067             0            0                0             0      42,184            0
 TEA/WSPP A                                   155,570       155,570             0            0                0             0           0            0
 TENASKA FRONTIER/EXS50                        11,451        11,451             0            0                0             0           0            0
 TENASKA FRONTIER/EXS75                         8,985         8,985             0            0                0             0           0            0
 TENASKA FRONTIER/EXS90                       145,651       145,651             0            0                0             0           0            0
 TENASKA/WSPP A                               327,729       317,683             0        5,820                0             0       4,226            0
 TENASKA/WSPP B                             3,213,034     3,046,016             0      146,370                0             0      20,648            0
 UNION POWER PARTNERS/WSPP A                   26,486        26,486             0            0                0             0           0            0
 UNION POWER PARTNERS/WSPP B               22,964,343    22,870,721             0            0                0             0      93,622            0
 WESTAR ENERGY NC/WSPP A                      966,608       966,608             0            0                0             0           0            0
 WESTAR ENERGY NC/WSPP B                    4,119,252     4,117,709             0            0                0             0       1,543            0
 WESTAR ENERGY NC/WSPP C                      111,520       111,520             0            0                0             0           0            0
 WRIGHTSVILE POWER/EXS75                        5,171         5,171             0            0                0             0           0            0
 WRIGHTSVILE POWER/EXS90                      113,362       113,362             0            0                0             0           0            0
 Attachment Snapshot: 20100826181933                           RunID: 17029                                              Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                               9-170
                                                                                                                        Exhibit PJC-2
                                                                                                                   2011 TX Rate Case
                                                                                                                         Page 9 of 70




 Entergy Electric System                     Date range - 20100701 through 20100731                                                       Attachment 1
 Intra-System Billing-201007RA         KWH Log Sheet Reconciliation - Entergy Mississippi, Inc.                                                 Page 9

                   Company                Net Gen         To Area           UPP       Exchange       Inadvertent       Firm Sales Sys Sales       Unacct

 YAZOO CITY/EXS90                                734             734              0              0                 0            0             0          0
 Un-accounted In                               2,701           2,701              0              0                 0            0             0          0
 Exchange                                165,417,337     165,416,077              0              0                 0            0             0      1,260
 INADVERTENT N                             2,134,214       2,134,214              0              0                 0            0             0          0

 Totals                                 1,669,714,232   1,633,071,080             0    32,027,550       3,063,696               0   1,549,246        2,660




 Attachment Snapshot: 20100826181933                             RunID: 17029                                                Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                                 9-171
                                                                                                                      Exhibit PJC-2
                                                                                                                 2011 TX Rate Case
                                                                                                                      Page 10 of 70




 Entergy Electric System                      Date range - 20100701 through 20100731                                                  Attachment 1
 Intra-System Billing-201007RA         KWH Log Sheet Reconciliation - Entergy New Orleans, Inc.                                            Page 10

                   Company                Net Gen        To Area           UPP       Exchange      Inadvertent    Firm Sales Sys Sales        Unacct

 AEP SERVICE CORP /MINDEN PAYBACK            (111,056)      (111,056)            0             0              0             0            0           0
 CALDWELL IMBAL IN                             58,420         58,420             0             0              0             0            0           0
 CALDWELL IMBAL OT                               (104)          (104)            0             0              0             0            0           0
 COG Sale Losses N                             40,983         40,983             0             0              0             0            0           0
 EPI-ISES ENOI IN                          34,395,193     34,395,193             0             0              0             0            0           0
 GIS Imbalance IN                              56,025         56,025             0             0              0             0            0           0
 GIS Imbalance OT                             (57,568)       (57,568)            0             0              0             0            0           0
 IPP Sale Losses N                            383,783        383,783             0             0              0             0            0           0
 JAS loss N                                        90             90             0             0              0             0            0           0
 KIRBYVILLE IMBAL IN                           27,836         27,836             0             0              0             0            0           0
 KIRBYVILLE IMBAL OT                             (285)          (285)            0             0              0             0            0           0
 NEWTON IMBAL IN                               44,723         44,723             0             0              0             0            0           0
 NEWTON IMBAL OT                                  (28)           (28)            0             0              0             0            0           0
 ARK.NU 1/NUCLEAR                          16,947,775     16,947,775             0             0              0             0            0           0
 ARK.NU 2/NUCLEAR                          19,989,454     19,989,454             0             0              0             0            0           0
 G.GULF 1/NUCLEAR                         141,859,390    141,859,390             0             0              0             0            0           0
 GGULF RET                                 13,799,542     13,799,542             0             0              0             0            0           0
 GGULF RP                                   6,514,363      6,514,363             0             0              0             0            0           0
 MICHOD 1/Aux                                (208,000)      (208,000)            0             0              0             0            0           0
 MICHOD 2/BRDGLN E                         17,595,495     17,411,762             0        62,252        116,111             0        5,370           0
 MICHOD 2/GSPL E                           56,709,373     56,651,579             0             0         45,575             0       12,219           0
 MICHOD 2/NOPSI I                           4,140,132      4,140,132             0             0              0             0            0           0
 MICHOD 3/Aux                              (1,663,000)    (1,663,000)            0             0              0             0            0           0
 MICHOD 3/BRDGLN E                         22,612,059     11,393,866             0    11,056,337        161,677             0            0         179
 MICHOD 3/GSPL E                           51,216,272     39,608,973             0    11,458,320        148,934             0            0          45
 MICHOD 3/NOPSI I                          10,702,389      5,463,663             0     5,187,011         51,715             0            0           0
 MICHOD 3/SIGPL E                           2,789,280      2,447,344             0       337,959          3,977             0            0           0
 RVRBND 1/NUCLEAR                          69,777,900     69,777,900             0             0              0             0            0           0
 INDEPN 1/COAL                              4,846,579      4,846,579             0             0              0             0            0           0
 WH.BLF 1/COAL                              8,494,462      8,494,462             0             0              0             0            0           0
 WH.BLF 2/COAL                              7,753,353      7,753,353             0             0              0             0            0           0
 AECC Excess BAILEY 1                          10,790          8,280             0           980          1,530             0            0           0
 AECC Excess INDEPN 2                           3,127          3,127             0             0              0             0            0           0
 AECC Excess MCCLEL 1                         713,178        383,473             0       315,602         14,103             0            0           0
 AECC Excess WH.BLF 1                         322,001        322,001             0             0              0             0            0           0
 AECC Excess WH.BLF 2                       1,572,080      1,572,080             0             0              0             0            0           0
 AECI/WSPP A                                  108,163        108,163             0             0              0             0            0           0
 AECI/WSPP B                                  904,000        904,000             0             0              0             0            0           0
 AECI/WSPP C SYSTEM FIRM                    2,082,590      1,473,723             0       608,021            134             0          712           0
 AEP SERVICE CORP /WSPP A                     135,600        135,600             0             0              0             0            0           0
 AEP SERVICE CORP /WSPP C                      36,160         36,160             0             0              0             0            0           0
 AMEREN ENERGY NC. (AE) ACTING                108,480         88,921             0        18,080          1,038             0          441           0
 Ameren Energy Marketing Company/WSPP           2,260          2,260             0             0              0             0            0           0
 BNP PARIBAS ENERGY TRADING                     9,040          9,040             0             0              0             0            0           0
 BNP PARIBAS ENERGY TRADING                   173,975        135,621             0        38,354              0             0            0           0
 CALP NE ENERGY SERVICES L.P./WSPP            603,872        600,536             0             0              0             0        3,336           0
 CARGILL POWER MARKETS LLC/WSPP A              75,710         75,710             0             0              0             0            0           0
 CITIGROUP ENERGY NC/WSPP A                    10,848         10,848             0             0              0             0            0           0
 CLECO/WSPP B                                 226,908        123,535             0        76,004          9,320             0       18,049           0
 CONSTELLATION ENERGY                           8,136          8,136             0             0              0             0            0           0
 CONSTELLATION ENERGY                         245,753        245,605             0             0              0             0          148           0
 COTTONWOOD ENERGY CO/EXS50                     9,005          9,005             0             0              0             0            0           0
 COTTONWOOD ENERGY CO/EXS75                     2,169          2,169             0             0              0             0            0           0
 COTTONWOOD ENERGY CO/EXS90                    94,934         94,934             0             0              0             0            0           0
 COTTONWOOD ENERGY CO/EXSSS50                     550            550             0             0              0             0            0           0
 COTTONWOOD ENERGY CO/EXSSTSH                  62,864         62,864             0             0              0             0            0           0
 CYPRES/EXS50                                     866            866             0             0              0             0            0           0
 CYPRES/EXS75                                      48             48             0             0              0             0            0           0
 CYPRES/EXS90                                   5,724          5,724             0             0              0             0            0           0
 DB ENERGY TRAD NG LLC/WSPP B               4,674,492      4,554,768             0        95,558              0             0       24,166           0
 DUKE ENERGY HINDS/EXS50                        5,123          5,123             0             0              0             0            0           0
 DUKE ENERGY HINDS/EXS75                        3,726          3,726             0             0              0             0            0           0
 DUKE ENERGY HINDS/EXS90                       39,071         39,071             0             0              0             0            0           0
 DUKEENERGY HOTSPRING/EXS50                     6,334          6,334             0             0              0             0            0           0
 DUKEENERGY HOTSPRING/EXS75                     3,804          3,804             0             0              0             0            0           0
 DUKEENERGY HOTSPRING/EXS90                    33,061         33,061             0             0              0             0            0           0
 DUKEENERGY HOTSPRING/FREE                         33             33             0             0              0             0            0           0
 ENDURE ENERGY/WSPP A                          61,475         52,943             0         8,272              0             0          260           0
 ENDURE ENERGY/WSPP B                           2,938          2,938             0             0              0             0            0           0
 ETEC/WSPP B                                   52,882         52,882             0             0              0             0            0           0
 EXELON GENERATION COMPANY                  4,226,539      4,219,874             0             0              0             0        6,665           0
 J ARON & COMPANY/WSPP B                    1,078,924        859,802             0       213,035          3,516             0        2,571           0
 J.P. MORGAN VENTURES ENERGY                    3,028          3,028             0             0              0             0            0           0
 J.P. MORGAN VENTURES ENERGY                  220,801        150,854             0        34,369         10,418             0       25,160           0
 JBO/WSPP A                                   437,129         72,048             0       268,090         39,665             0       57,191         135
 Attachment Snapshot: 20100826181933                            RunID: 17029                                             Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                               9-172
                                                                                                                      Exhibit PJC-2
                                                                                                                 2011 TX Rate Case
                                                                                                                      Page 11 of 70




 Entergy Electric System                       Date range - 20100701 through 20100731                                                 Attachment 1
 Intra-System Billing-201007RA          KWH Log Sheet Reconciliation - Entergy New Orleans, Inc.                                           Page 11

                   Company                 Net Gen       To Area           UPP       Exchange      Inadvertent    Firm Sales Sys Sales        Unacct

 JBO/WSPP B                                    469,404       240,761             0      217,346               0             0       11,297           0
 KANSAS CITY POWER & LIGHT                      65,133        65,133             0            0               0             0            0           0
 MAGNET COVE/EXS75                                 767           767             0            0               0             0            0           0
 MAGNET COVE/EXS90                              35,498        35,498             0            0               0             0            0           0
 MAGNET COVE/EXSSTSH                           195,248       195,248             0            0               0             0            0           0
 MDEA CROSSROADS/EXS50                           1,052         1,052             0            0               0             0            0           0
 MDEA CROSSROADS/EXS75                             212           212             0            0               0             0            0           0
 MDEA CROSSROADS/EXS90                           7,416         7,416             0            0               0             0            0           0
 MERRILL LYNCH COMMODITIES                   8,771,914     8,721,872             0            0               0             0       50,042           0
 MORGAN STANLEY/WSPP A                          11,118        11,118             0            0               0             0            0           0
 NRG POWER MARKETING LLC./WSPP A             1,345,830     1,278,030             0       67,800               0             0            0           0
 NRG POWER MARKETING LLC./WSPP B             8,356,751     7,962,176             0      280,383          30,425             0       83,767           0
 NRG POWER MARKETING LLC./WSPP C               376,742       304,422             0       70,969               0             0        1,351           0
 OCCIDENTAL POWER SERVICES/WSPP                257,550       182,926             0       40,184          20,217             0       14,178          45
 RAINBOW ENERGY MARKETING                      629,363       629,363             0            0               0             0            0           0
 SMEPA/WSPP B                                  135,600             0             0      134,472               0             0        1,128           0
 SOUTHERN COMPANY SERVICES INC.                 24,860        24,860             0            0               0             0            0           0
 SOUTHERN COMPANY SERVICES INC.                479,120             0             0      418,166               0             0       60,954           0
 SUEZ Energy Marketing NA Inc./WSPP A          391,432       391,432             0            0               0             0            0           0
 SUEZ Energy Marketing NA Inc./WSPP B        2,555,470     2,541,792             0            0               0             0       13,678           0
 TEA/WSPP A                                     50,443        50,443             0            0               0             0            0           0
 TENASKA FRONTIER/EXS50                          3,714         3,714             0            0               0             0            0           0
 TENASKA FRONTIER/EXS75                          2,912         2,912             0            0               0             0            0           0
 TENASKA FRONTIER/EXS90                         47,232        47,232             0            0               0             0            0           0
 TENASKA/WSPP A                                106,266       104,270             0            0             626             0        1,370           0
 TENASKA/WSPP B                              1,041,808       480,385             0      554,729               0             0        6,694           0
 UNION POWER PARTNERS/WSPP A                     8,588         8,588             0            0               0             0            0           0
 UNION POWER PARTNERS/WSPP B                 7,446,119     7,415,760             0            0               0             0       30,359           0
 WESTAR ENERGY NC/WSPP A                       313,419       313,419             0            0               0             0            0           0
 WESTAR ENERGY NC/WSPP B                     1,335,662     1,335,162             0            0               0             0          500           0
 WESTAR ENERGY NC/WSPP C                        36,160        10,120             0       25,251             789             0            0           0
 WRIGHTSVILE POWER/EXS75                         1,675         1,675             0            0               0             0            0           0
 WRIGHTSVILE POWER/EXS90                        36,734        36,734             0            0               0             0            0           0
 YAZOO CITY/EXS90                                  237           237             0            0               0             0            0           0
 Un-accounted In                                   865           865             0            0               0             0            0           0
 Exchange                                   45,025,369    44,705,819             0            0         319,102             0            0         448
 INADVERTENT N                                 692,014       692,014             0            0               0             0            0           0

 Totals                                    587,352,718   554,353,844             0    31,587,544        978,872             0     431,606          852




 Attachment Snapshot: 20100826181933                            RunID: 17029                                             Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                               9-173
                                                                                                                     Exhibit PJC-2
                                                                                                                2011 TX Rate Case
                                                                                                                     Page 12 of 70




 Entergy Electric System                  Date range - 20100701 through 20100731                                                     Attachment 1
 Intra-System Billing-201007RA KWH Log Sheet Reconciliation - Entergy Gulf States Louisiana, LLC                                          Page 12

                   Company             Net Gen        To Area           UPP         Exchange      Inadvertent    Firm Sales Sys Sales        Unacct

 AEP SERVICE CORP /MINDEN PAYBACK         (471,276)      (471,276)              0             0              0             0            0           0
 CALDWELL IMBAL IN                         247,500        247,500               0             0              0             0            0           0
 CALDWELL IMBAL OT                            (446)          (446)              0             0              0             0            0           0
 CALP NE A BASE IN                     137,098,200    137,098,200               0             0              0             0            0           0
 CALP NE B BASE IN                      98,223,400     98,142,376               0        71,559          9,465             0            0           0
 CALP NE C BASE IN                       5,787,100      5,787,100               0             0              0             0            0           0
 CALP NE B RAMP IN                       1,973,300      1,973,300               0             0              0             0            0           0
 CALP NE C RAMP IN                          34,100         34,100               0             0              0             0            0           0
 CALP NE EXCESS N                          422,000        422,000               0             0              0             0            0           0
 CLEC - RICHARDLOSSES                      279,000        279,000               0             0              0             0            0           0
 CLECO/TOLEDO BEND                      (1,206,925)    (1,206,925)              0             0              0             0            0           0
 COG Sale Losses N                         173,685        173,685               0             0              0             0            0           0
 GIS Imbalance IN                          237,396        237,396               0             0              0             0            0           0
 GIS Imbalance OT                         (243,779)      (243,779)              0             0              0             0            0           0
 IPP Sale Losses N                       1,625,895      1,625,895               0             0              0             0            0           0
 JAS loss N                                    383            383               0             0              0             0            0           0
 KIRBYVILLE IMBAL IN                       117,953        117,953               0             0              0             0            0           0
 KIRBYVILLE IMBAL OT                        (1,205)        (1,205)              0             0              0             0            0           0
 NEWTON IMBAL IN                           189,491        189,491               0             0              0             0            0           0
 NEWTON IMBAL OT                              (116)          (116)              0             0              0             0            0           0
 ARK.NU 1/NUCLEAR                       15,851,160     15,851,160               0             0              0             0            0           0
 ARK.NU 2/NUCLEAR                       18,809,417     18,809,417               0             0              0             0            0           0
 CALCAS EU 1                             4,690,725              0       4,690,725             0              0             0            0           0
 CALCAS EU 1/Aux                          (332,000)      (332,000)              0             0              0             0            0           0
 CALCAS EU 1/GSPL E                      5,798,159      1,980,749               0     3,714,474        102,936             0            0           0
 CALCAS EU 1/GSPL I                        548,116              0               0       548,116              0             0            0           0
 CALCAS EU 2                             5,250,450              0       5,250,450             0              0             0            0           0
 CALCAS EU 2/GSPL E                      7,103,550      4,163,301               0     2,906,170         34,079             0            0           0
 GGULF RET                              11,616,357     11,616,357               0             0              0             0            0           0
 GGULF RP                                5,876,574      5,876,574               0             0              0             0            0           0
 LEWIS CREEK 1/COPANO E                  4,754,332      2,871,914               0     1,879,528          2,890             0            0           0
 LEWIS CREEK 1/COPANO M                 27,587,139     16,462,009               0    10,925,536        184,068             0       15,337         189
 LEWIS CREEK 1/TETCO E                   6,385,297      4,739,291               0     1,521,741        117,176             0        6,900         189
 LEWIS CREEK 1/TETCO I                   2,320,478      1,154,988               0     1,157,040          8,450             0            0           0
 LEWIS CREEK 1/TETCO M                  17,169,779     13,456,160               0     3,647,410         64,331             0        1,878           0
 LEWIS CREEK 2/COPANO E                  6,018,572      5,010,477               0       926,721         81,364             0           10           0
 LEWIS CREEK 2/COPANO M                  6,495,036      2,992,409               0     3,483,050         18,869             0          519         189
 LEWIS CREEK 2/TEJAS E                   1,084,656        942,834               0       141,822              0             0            0           0
 LEWIS CREEK 2/TETCO E                  27,574,206     26,009,942               0     1,536,278         15,490             0       12,307         189
 LEWIS CREEK 2/TETCO I                   8,137,353      6,515,658               0     1,582,353         37,936             0        1,239         167
 LEWIS CREEK 2/TETCO M                  16,415,552     10,969,861               0     5,315,248        116,297             0       13,767         379
 NELSON 3                                5,192,225              0       5,192,225             0              0             0            0           0
 NELSON 3/Aux                             (443,000)      (443,000)              0             0              0             0            0           0
 NELSON 3/TARGA E                          284,050         71,574               0       211,896            580             0            0           0
 NELSON 3/TENN M                         2,091,290        322,313               0     1,700,865         68,112             0            0           0
 NELSON 3/TETCO E                          346,150         13,227               0       310,513         22,410             0            0           0
 NELSON 3/TETCO M                        4,303,285        113,170               0     4,149,185         40,930             0            0           0
 NELSON 4                               62,280,775              0      62,280,775             0              0             0            0           0
 NELSON 4/Aux                           (1,398,000)    (1,398,000)              0             0              0             0            0           0
 NELSON 4/FLORIDA E                      8,300,163      1,243,147               0     7,000,169         56,847             0            0           0
 NELSON 4/TARGA E                       19,008,705      4,409,283               0    14,524,924         74,498             0            0           0
 NELSON 4/TENN E                        16,820,496      4,323,987               0    12,398,148         98,361             0            0           0
 NELSON 4/TENN M                        12,742,940      1,116,094               0    11,564,685         61,325             0          836           0
 NELSON 4/TETCO E                          850,947        154,177               0       673,803         22,967             0            0           0
 NELSON 4/TETCO I                        4,447,488        342,815               0     4,071,417         33,255             0            1           0
 NELSON 4/TETCO M                       22,091,486      1,025,802               0    20,958,943         86,765             0       19,976           0
 NELSON 6/GSU COAL                     151,437,989    151,437,989               0             0              0             0            0           0
 OUACHITA 3/SIGCO I                      7,773,099      7,773,099               0             0              0             0            0           0
 OUACHITA 3/SIGPL E                     33,557,901     33,557,901               0             0              0             0            0           0
 PERVIL 1                               82,838,753              0      82,838,753             0              0             0            0           0
 PERVIL 1/TENN E                        90,584,771     90,584,771               0             0              0             0            0           0
 PERVIL 1/TENN I                        10,157,373     10,157,373               0             0              0             0            0           0
 PERVIL 1/TEXAS GAS E                   11,333,603     11,333,603               0             0              0             0            0           0
 RVRBND 1                              416,923,129              0     416,923,129             0              0             0            0           0
 RVRBND 1/Aux                             (636,000)      (636,000)              0             0              0             0            0           0
 RVRBND 1/NUCLEAR                      280,855,871    280,855,871               0             0              0             0            0           0
 SABINE 1/CENTANA#3 E                    1,991,296      1,428,431               0       528,309         34,556             0            0           0
 SABINE 1/CENTANA#3 M                   14,139,569      2,927,977               0    11,158,610         52,407             0          575           0
 SABINE 1/ENBRIDGE E                     7,109,237      4,073,972               0     2,981,642         53,617             0            6           0
 SABINE 1/ENBRIDGE M                    19,334,191      5,734,266               0    13,526,870         59,310             0       13,745           0
 SABINE 1/HPL/CH E                       2,454,586      1,411,802               0       988,225         54,559             0            0           0
 SABINE 1/STORAGE I                      3,963,609      2,456,407               0     1,426,945         80,257             0            0           0
 SABINE 1/TEJAS E                          132,959         11,300               0       121,659              0             0            0           0
 SABINE 1/TEJAS M                        2,020,803      1,063,465               0       947,156         10,182             0            0           0
 SABINE 2/CENTANA#3 E                    1,067,826        975,918               0        91,908              0             0            0           0
 Attachment Snapshot: 20100826181933                         RunID: 17029                                               Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                              9-174
                                                                                                                      Exhibit PJC-2
                                                                                                                 2011 TX Rate Case
                                                                                                                      Page 13 of 70




 Entergy Electric System                  Date range - 20100701 through 20100731                                                      Attachment 1
 Intra-System Billing-201007RA KWH Log Sheet Reconciliation - Entergy Gulf States Louisiana, LLC                                           Page 13

                   Company              Net Gen        To Area           UPP         Exchange      Inadvertent    Firm Sales Sys Sales        Unacct

 SABINE 2/CENTANA#3 M                     1,640,764        962,855               0       664,972         12,937             0           0            0
 SABINE 2/ENBRIDGE E                     18,075,411     17,296,375               0       692,152         71,934             0      14,950            0
 SABINE 2/ENBRIDGE M                     15,307,706      8,209,508               0     7,036,036         60,197             0       1,398          567
 SABINE 2/STORAGE I                      10,780,443     10,735,018               0        44,850              0             0         575            0
 SABINE 2/TEJAS M                         3,689,900      2,689,320               0       908,661         91,919             0           0            0
 SABINE 3/CENTANA#3 E                     2,359,458      1,271,924               0     1,060,597         26,937             0           0            0
 SABINE 3/CENTANA#3 M                    26,532,333     10,193,621               0    16,217,549        117,137             0       4,026            0
 SABINE 3/ENBRIDGE E                     11,275,875      8,080,644               0     3,103,193         91,859             0         179            0
 SABINE 3/ENBRIDGE M                     26,260,809     13,818,877               0    12,241,869        199,424             0          71          568
 SABINE 3/HPL/CH E                        1,994,197      1,664,112               0       326,498          3,587             0           0            0
 SABINE 3/STORAGE I                          61,879         51,555               0        10,324              0             0           0            0
 SABINE 3/TEJAS E                         2,651,427      1,706,812               0       925,496         18,930             0           0          189
 SABINE 3/TEJAS M                         8,961,522      1,724,865               0     7,186,222         49,860             0         575            0
 SABINE 4/CENTANA#3 M                     9,048,063      8,594,274               0       453,221            568             0           0            0
 SABINE 4/ENBRIDGE E                     28,033,463     25,240,374               0     2,601,263        191,251             0         575            0
 SABINE 4/ENBRIDGE M                     19,827,303     17,470,401               0     2,257,273         99,607             0           0           22
 SABINE 4/HPL/CH E                        1,071,225        923,196               0       123,231         24,798             0           0            0
 SABINE 4/STORAGE I                      13,195,044     12,757,477               0       354,533         83,034             0           0            0
 SABINE 4/TEJAS M                         4,992,852      4,447,031               0       540,521          5,300             0           0            0
 SABINE 5/CENTANA#3 M                    14,674,847      1,675,960               0    12,993,537          5,338             0          12            0
 SABINE 5/ENBRIDGE E                      4,577,833        961,570               0     3,605,523         10,551             0           0          189
 SABINE 5/ENBRIDGE M                      3,761,796         42,310               0     3,707,371         12,115             0           0            0
 SABINE 5/HPL/CH E                        2,185,515        119,242               0     2,059,458          6,815             0           0            0
 SABINE 5/TEJAS E                         1,859,403        210,670               0     1,643,812          4,921             0           0            0
 SABINE 5/TEJAS M                        43,874,331      4,833,677               0    38,907,022        133,443             0           0          189
 TOLEDO 1/HYDRO                           3,875,207      3,875,207               0             0              0             0           0            0
 WILLOW GLEN 1                            5,445,950              0       5,445,950             0              0             0           0            0
 WILLOW GLEN 1/Aux                           (8,000)        (8,000)              0             0              0             0           0            0
 WILLOW GLEN 1/BL HOLDINGS E              7,368,050        282,945               0     7,061,062         24,043             0           0            0
 WILLOW GLEN 2                           10,391,250              0      10,391,250             0              0             0           0            0
 WILLOW GLEN 2/Aux                         (313,000)      (313,000)              0             0              0             0           0            0
 WILLOW GLEN 2/BL HOLDINGS E             14,058,750        747,921               0    13,042,792        265,448             0       2,589            0
 WILLOW GLEN 3/Aux                         (218,000)      (218,000)              0             0              0             0           0            0
 WILLOW GLEN 4                           77,447,750              0      77,447,750             0              0             0           0            0
 WILLOW GLEN 4/Aux                         (193,000)      (193,000)              0             0              0             0           0            0
 WILLOW GLEN 4/BL HOLDINGS E            104,782,250     35,620,086               0    68,607,715        551,523             0       2,358          568
 WILLOW GLEN 5/Aux                         (203,000)      (203,000)              0             0              0             0           0            0
 INDEPN 1/COAL                            4,526,010      4,526,010               0             0              0             0           0            0
 WH.BLF 1/COAL                            8,331,086      8,331,086               0             0              0             0           0            0
 WH.BLF 2/COAL                            7,011,078      7,011,078               0             0              0             0           0            0
 AECC Excess BAILEY 1                        46,025         20,538               0        24,335          1,152             0           0            0
 AECC Excess INDEPN 2                        13,248         13,248               0             0              0             0           0            0
 AECC Excess MCCLEL 1                     3,021,702        211,103               0     2,792,163         18,436             0           0            0
 AECC Excess WH.BLF 1                     1,364,211      1,364,211               0             0              0             0           0            0
 AECC Excess WH.BLF 2                     6,660,472      6,660,472               0             0              0             0           0            0
 ACADIA POWER PARTNERS, LLC/WSPP         59,708,320     59,675,508               0             0              0             0      32,812            0
 AECI/WSPP A                                458,259        458,259               0             0              0             0           0            0
 AECI/WSPP B                              3,830,000      3,830,000               0             0              0             0           0            0
 AECI/WSPP C SYSTEM FIRM                  8,823,362      5,646,503               0     3,173,844              0             0       3,015            0
 AEP SERVICE CORP /WSPP A                   574,500        574,500               0             0              0             0           0            0
 AEP SERVICE CORP /WSPP C                   153,200        153,200               0             0              0             0           0            0
 AGRILECTRIC/QF                           5,310,500      5,297,791               0        12,709              0             0           0            0
 AIR LIQUIDE AMERICA/QF                     512,000        512,000               0             0              0             0           0            0
 AMEREN ENERGY NC. (AE) ACTING              459,600        153,200               0       304,529              0             0       1,871            0
 Ameren Energy Marketing Company/WSPP         9,575          9,575               0             0              0             0           0            0
 BNP PARIBAS ENERGY TRADING                  38,300         38,300               0             0              0             0           0            0
 BNP PARIBAS ENERGY TRADING                 737,083        675,803               0        61,280              0             0           0            0
 CALP NE ENERGY SERVICES L.P./WSPP        2,558,432      2,343,869               0       193,011          7,415             0      14,137            0
 CARGILL POWER MARKETS LLC/WSPP A           320,760        320,760               0             0              0             0           0            0
 CITIGROUP ENERGY NC/WSPP A                  45,959         45,959               0             0              0             0           0            0
 CLECO/WSPP B                               961,242         49,715               0       830,943          4,096             0      76,488            0
 CONOCOPH LLIPS COMPANY /INTRA-           1,969,375        287,500               0     1,681,875              0             0           0            0
 CONSTELLATION ENERGY                        34,469         34,469               0             0              0             0           0            0
 CONSTELLATION ENERGY                     1,041,185      1,040,557               0             0              0             0         628            0
 COTTONWOOD ENERGY CO/EXS50                  38,172         38,172               0             0              0             0           0            0
 COTTONWOOD ENERGY CO/EXS75                   9,218          9,218               0             0              0             0           0            0
 COTTONWOOD ENERGY CO/EXS90                 402,325        402,325               0             0              0             0           0            0
 COTTONWOOD ENERGY CO/EXSSS50                 2,330          2,330               0             0              0             0           0            0
 COTTONWOOD ENERGY CO/EXSSTSH               266,318        266,318               0             0              0             0           0            0
 CYPRES/EXS50                                 3,667          3,667               0             0              0             0           0            0
 CYPRES/EXS75                                   201            201               0             0              0             0           0            0
 CYPRES/EXS90                                24,238         24,238               0             0              0             0           0            0
 DB ENERGY TRAD NG LLC/WSPP B            19,804,486     17,993,200               0     1,654,147         54,752             0     102,387            0
 DOW CHEMICAL/QF                        227,204,450    227,080,662               0       123,788              0             0           0            0
 DOW P PELINE COMPANY/INTRA-DAY           2,127,500              0               0     2,116,638              0             0      10,862            0
 Attachment Snapshot: 20100826181933                          RunID: 17029                                               Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                               9-175
                                                                                                                         Exhibit PJC-2
                                                                                                                    2011 TX Rate Case
                                                                                                                         Page 14 of 70




 Entergy Electric System                  Date range - 20100701 through 20100731                                                         Attachment 1
 Intra-System Billing-201007RA KWH Log Sheet Reconciliation - Entergy Gulf States Louisiana, LLC                                              Page 14

                   Company                Net Gen         To Area           UPP         Exchange      Inadvertent    Firm Sales Sys Sales        Unacct

 DUKE ENERGY HINDS/EXS50                      21,701          21,701               0              0              0             0           0             0
 DUKE ENERGY HINDS/EXS75                      15,831          15,831               0              0              0             0           0             0
 DUKE ENERGY HINDS/EXS90                     165,827         165,827               0              0              0             0           0             0
 DUKEENERGY HOTSPRING/EXS50                   26,842          26,842               0              0              0             0           0             0
 DUKEENERGY HOTSPRING/EXS75                   16,148          16,148               0              0              0             0           0             0
 DUKEENERGY HOTSPRING/EXS90                  140,121         140,121               0              0              0             0           0             0
 DUKEENERGY HOTSPRING/FREE                       144             144               0              0              0             0           0             0
 ENDURE ENERGY/WSPP A                        260,432         224,289               0         35,043              0             0       1,100             0
 ENDURE ENERGY/WSPP B                         12,447          12,447               0              0              0             0           0             0
 ETEC/WSPP B                                 224,050         224,050               0              0              0             0           0             0
 EXELON GENERATION COMPANY                17,906,524      17,818,311               0         53,551          6,436             0      28,226             0
 EXXON ENCO/QF                            21,120,565      21,120,565               0              0              0             0           0             0
 EXXON ESSO/QF                             7,447,850       7,447,850               0              0              0             0           0             0
 EXXON EXXON/QF                            5,300,520       5,300,520               0              0              0             0           0             0
 FORMOSA PLASTICS/QF                       1,778,370       1,778,370               0              0              0             0           0             0
 GAPACIFIC/QF                                165,150         165,150               0              0              0             0           0             0
 J ARON & COMPANY/WSPP B                   4,571,051       2,465,103               0      2,095,052              0             0      10,896             0
 J.P. MORGAN VENTURES ENERGY                  12,830          12,830               0              0              0             0           0             0
 J.P. MORGAN VENTURES ENERGY                 935,473               0               0        828,870              0             0     106,603             0
 JBO/WSPP A                                1,851,983               0               0      1,609,650              0             0     242,333             0
 JBO/WSPP B                                1,988,687         803,309               0      1,137,518              0             0      47,860             0
 KANSAS CITY POWER & LIGHT                   275,952         275,952               0              0              0             0           0             0
 MAGNET COVE/EXS75                             3,251           3,251               0              0              0             0           0             0
 MAGNET COVE/EXS90                           150,472         150,472               0              0              0             0           0             0
 MAGNET COVE/EXSSTSH                         827,228         827,228               0              0              0             0           0             0
 MDEA CROSSROADS/EXS50                         4,443           4,443               0              0              0             0           0             0
 MDEA CROSSROADS/EXS75                           896             896               0              0              0             0           0             0
 MDEA CROSSROADS/EXS90                        31,427          31,427               0              0              0             0           0             0
 MERRILL LYNCH COMMODITIES                37,164,138      36,370,473               0        513,751         67,902             0     212,012             0
 MORGAN STANLEY/WSPP A                        47,110          47,110               0              0              0             0           0             0
 NRG CAJUN 3/CAJUN 3                      95,955,425      95,955,425               0              0              0             0           0             0
 NRG POWER MARKETING LLC./WSPP A           5,701,912       5,414,662               0        287,250              0             0           0             0
 NRG POWER MARKETING LLC./WSPP B          35,405,012      31,125,729               0      3,866,468         57,925             0     354,890             0
 NRG POWER MARKETING LLC./WSPP C           1,596,150       1,014,374               0        576,051              0             0       5,725             0
 OCCIDENTAL POWER SERVICES/WSPP            1,091,166         162,610               0        860,110          8,372             0      60,074             0
 PPG INDUSTR ES/QF                       169,586,800     169,586,800               0              0              0             0           0             0
 RAINBOW ENERGY MARKETING                  2,666,424       2,649,436               0         16,988              0             0           0             0
 SHELL WOODSTOCK/QF                       13,180,862      13,165,150               0              0         15,712             0           0             0
 SMEPA/WSPP B                                574,496               0               0        569,717              0             0       4,779             0
 SOUTHERN COMPANY SERVICES INC.              105,325         105,325               0              0              0             0           0             0
 SOUTHERN COMPANY SERVICES INC.            2,029,900               0               0      1,771,646              0             0     258,254             0
 SUEZ Energy Marketing NA Inc./WSPP A      1,658,371       1,658,371               0              0              0             0           0             0
 SUEZ Energy Marketing NA Inc./WSPP B     10,826,823      10,663,125               0         87,489         18,262             0      57,947             0
 TEA/WSPP A                                  213,711         213,711               0              0              0             0           0             0
 TENASKA FRONTIER/EXS50                       15,731          15,731               0              0              0             0           0             0
 TENASKA FRONTIER/EXS75                       12,343          12,343               0              0              0             0           0             0
 TENASKA FRONTIER/EXS90                      200,195         200,195               0              0              0             0           0             0
 TENASKA/WSPP A                              450,215         190,542               0        253,868              0             0       5,805             0
 TENASKA/WSPP B                            4,413,862       1,602,890               0      2,782,607              0             0      28,365             0
 UNION POWER PARTNERS/WSPP A                  36,384          36,384               0              0              0             0           0             0
 UNION POWER PARTNERS/WSPP B              31,547,047      30,407,933               0        993,273         17,226             0     128,615             0
 Un-accounted In                               3,652           3,652               0              0              0             0           0             0
 WESTAR ENERGY NC/WSPP A                   1,327,853       1,327,853               0              0              0             0           0             0
 WESTAR ENERGY NC/WSPP B                   5,658,817       5,558,739               0         97,958              0             0       2,120             0
 WESTAR ENERGY NC/WSPP C                     153,200               0               0        153,200              0             0           0             0
 WRIGHTSVILE POWER/EXS75                       7,107           7,107               0              0              0             0           0             0
 WRIGHTSVILE POWER/EXS90                     155,716         155,716               0              0              0             0           0             0
 YAZOO CITY/EXS90                              1,011           1,011               0              0              0             0           0             0
 Exchange                                  8,681,301       8,681,301               0              0              0             0           0             0
 INADVERTENT N                             2,931,814       2,931,814               0              0              0             0           0             0

 Totals                                 3,103,786,681   2,038,635,428     670,461,007   388,628,993      4,145,451             0   1,912,208        3,594




 Attachment Snapshot: 20100826181933                             RunID: 17029                                               Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                                  9-176
                                                                                                                      Exhibit PJC-2
                                                                                                                 2011 TX Rate Case
                                                                                                                      Page 15 of 70




 Entergy Electric System                    Date range - 20100701 through 20100731                                                    Attachment 1
 Intra-System Billing-201007RA          KWH Log Sheet Reconciliation - Entergy Texas, Inc                                                  Page 15

                   Company              Net Gen         To Area           UPP         Exchange     Inadvertent    Firm Sales Sys Sales        Unacct

 AEP SERVICE CORP /MINDEN PAYBACK          (412,346)       (412,346)              0            0              0             0            0           0
 CALDWELL IMBAL IN                          211,422         211,422               0            0              0             0            0           0
 CALDWELL IMBAL OT                             (390)           (390)              0            0              0             0            0           0
 CLECO/TOLEDO BEND                         (892,075)       (892,075)              0            0              0             0            0           0
 COG Sale Losses N                          148,409         148,409               0            0              0             0            0           0
 CYPRESS - ETEC                           1,057,000       1,057,000               0            0              0             0            0           0
 EPMCNELSON6 - CLEC                        (774,000)       (774,000)              0            0              0             0            0           0
 EPMCNELSON6 - CNWY                         (10,000)        (10,000)              0            0              0             0            0           0
 EPMCNELSON6 - DERS                         (10,000)        (10,000)              0            0              0             0            0           0
 EPMCNELSON6 - MDEA                      (1,018,000)     (1,018,000)              0            0              0             0            0           0
 EPMCNELSON6 - SOCO                         (78,000)        (78,000)              0            0              0             0            0           0
 EPMCNELSON6 - SWPP                      (3,294,000)     (3,294,000)              0            0              0             0            0           0
 ETEC EXCESS-CONTRAOT                        (4,937)         (4,937)              0            0              0             0            0           0
 ETEC EXCESS-HRSNHRDN                         4,937           4,937               0            0              0             0            0           0
 ETI SALE TO ETEC IN                     87,385,599      87,385,599               0            0              0             0            0           0
 EXELON FRONT ER 10YR                    93,424,000      93,424,000               0            0              0             0            0           0
 GIS Imbalance IN                           202,815         202,815               0            0              0             0            0           0
 GIS Imbalance OT                          (213,386)       (213,386)              0            0              0             0            0           0
 HARDIN                                   9,029,000       9,029,000               0            0              0             0            0           0
 INTERNAL LOAD IN                        21,576,000      21,576,000               0            0              0             0            0           0
 IPP Sale Losses N                        1,389,104       1,389,104               0            0              0             0            0           0
 JAS loss N                                     327             327               0            0              0             0            0           0
 KIRBYVILLE IMBAL IN                        100,758         100,758               0            0              0             0            0           0
 KIRBYVILLE IMBAL OT                         (1,053)         (1,053)              0            0              0             0            0           0
 NEWTON IMBAL IN                            161,878         161,878               0            0              0             0            0           0
 NEWTON IMBAL OT                               (102)           (102)              0            0              0             0            0           0
 RSCOGEN - SRMPA                          8,470,000       8,470,000               0            0              0             0            0           0
 SAN JACINTO 1                            5,722,000       5,722,000               0            0              0             0            0           0
 SAN JACINTO 2                            5,612,000       5,612,000               0            0              0             0            0           0
 SR ACT LOAD       OT                  (208,678,469)   (208,678,469)              0            0              0             0            0           0
 SR ACT LOAD IN ETI                      27,893,256      27,893,256               0            0              0             0            0           0
 SRMA LOAD        OT                    (37,747,524)    (37,747,524)              0            0              0             0            0           0
 SWPP - ETEC                             20,505,000      20,505,000               0            0              0             0            0           0
 ARK.NU 1/NUCLEAR                        16,654,966      16,654,966               0            0              0             0            0           0
 ARK.NU 2/NUCLEAR                        19,768,134      19,768,134               0            0              0             0            0           0
 CALCAS EU 1/GSPL E                       4,285,611       4,285,611               0            0              0             0            0           0
 CALCAS EU 1/GSPL I                         405,114         405,114               0            0              0             0            0           0
 CALCAS EU 2/GSPL E                       5,250,450       5,250,450               0            0              0             0            0           0
 GGULF RET                               12,205,279      12,205,279               0            0              0             0            0           0
 GGULF RP                                 6,173,783       6,173,783               0            0              0             0            0           0
 LEWIS CREEK 1                           58,217,025               0      58,217,025            0              0             0            0           0
 LEWIS CREEK 1/COPANO E                   3,513,838       3,513,838               0            0              0             0            0           0
 LEWIS CREEK 1/COPANO M                  20,390,449      20,379,112               0            0              0             0       11,337           0
 LEWIS CREEK 1/TETCO E                    4,719,555       4,714,455               0            0              0             0        5,100           0
 LEWIS CREEK 1/TETCO I                    1,715,190       1,715,190               0            0              0             0            0           0
 LEWIS CREEK 1/TETCO M                   12,690,943      12,689,556               0            0              0             0        1,387           0
 LEWIS CREEK 2                           65,725,375               0      65,725,375            0              0             0            0           0
 LEWIS CREEK 2/Aux                           (9,000)         (9,000)              0            0              0             0            0           0
 LEWIS CREEK 2/COPANO E                   4,448,495       4,448,487               0            0              0             0            8           0
 LEWIS CREEK 2/COPANO M                   4,800,621       4,800,236               0            0              0             0          385           0
 LEWIS CREEK 2/TEJAS E                      801,683         801,683               0            0              0             0            0           0
 LEWIS CREEK 2/TETCO E                   20,380,744      20,371,648               0            0              0             0        9,096           0
 LEWIS CREEK 2/TETCO I                    6,014,580       6,013,664               0            0              0             0          916           0
 LEWIS CREEK 2/TETCO M                   12,133,502      12,123,325               0            0              0             0       10,177           0
 NELSON 3/TARGA E                           209,950         207,485               0            0          2,465             0            0           0
 NELSON 3/TENN M                          1,545,767       1,401,589               0            0        144,178             0            0           0
 NELSON 3/TETCO E                           255,850         101,536               0            0        154,314             0            0           0
 NELSON 3/TETCO M                         3,180,658       2,478,395               0            0        702,263             0            0           0
 NELSON 4/FLORIDA E                       6,135,214       6,087,711               0       47,337              0             0            0         166
 NELSON 4/TARGA E                        14,050,111      13,926,196               0      121,380          2,535             0            0           0
 NELSON 4/TENN E                         12,432,537      12,414,755               0       17,782              0             0            0           0
 NELSON 4/TENN M                          9,418,739       9,253,513               0       57,443        107,165             0          618           0
 NELSON 4/TETCO E                           628,945         626,428               0            0          2,517             0            0           0
 NELSON 4/TETCO I                         3,287,176       3,287,175               0            0              0             0            1           0
 NELSON 4/TETCO M                        16,328,053      15,846,269               0      177,010        290,009             0       14,765           0
 NELSON 6/GSU COAL                      224,805,011     224,805,011               0            0              0             0            0           0
 PERVIL 1/TENN E                         66,954,359      66,954,359               0            0              0             0            0           0
 PERVIL 1/TENN I                          7,507,634       7,507,634               0            0              0             0            0           0
 PERVIL 1/TEXAS GAS E                     8,376,760       8,376,760               0            0              0             0            0           0
 RVRBND 1/NUCLEAR                       207,589,429     207,589,429               0            0              0             0            0           0
 SABINE 1                                51,146,250               0      51,146,250            0              0             0            0           0
 SABINE 1/Aux                              (183,000)       (183,000)              0            0              0             0            0           0
 SABINE 1/CENTANA#3 E                     1,471,820       1,471,820               0            0              0             0            0           0
 SABINE 1/CENTANA#3 M                    10,450,916      10,449,828               0            0              0             0          425         663
 SABINE 1/ENBRIDGE E                      5,254,580       5,254,575               0            0              0             0            5           0
 Attachment Snapshot: 20100826181933                           RunID: 17029                                              Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                               9-177
                                                                                                                   Exhibit PJC-2
                                                                                                              2011 TX Rate Case
                                                                                                                   Page 16 of 70




 Entergy Electric System                    Date range - 20100701 through 20100731                                                 Attachment 1
 Intra-System Billing-201007RA          KWH Log Sheet Reconciliation - Entergy Texas, Inc                                               Page 16

                   Company              Net Gen       To Area          UPP         Exchange     Inadvertent    Firm Sales Sys Sales        Unacct

 SABINE 1/ENBRIDGE M                    14,290,597    14,280,438               0            0              0             0       10,159           0
 SABINE 1/HPL/CH E                       1,814,305     1,814,305               0            0              0             0            0           0
 SABINE 1/STORAGE I                      2,929,631     2,929,631               0            0              0             0            0           0
 SABINE 1/TEJAS E                           98,285        98,285               0            0              0             0            0           0
 SABINE 1/TEJAS M                        1,493,616     1,493,616               0            0              0             0            0           0
 SABINE 2                               50,562,050             0      50,562,050            0              0             0            0           0
 SABINE 2/CENTANA#3 E                      789,282       789,282               0            0              0             0            0           0
 SABINE 2/CENTANA#3 M                    1,212,690     1,212,690               0            0              0             0            0           0
 SABINE 2/ENBRIDGE E                    13,360,029    13,348,979               0            0              0             0       11,050           0
 SABINE 2/ENBRIDGE M                    11,314,406    11,313,373               0            0              0             0        1,033           0
 SABINE 2/STORAGE I                      7,968,187     7,967,762               0            0              0             0          425           0
 SABINE 2/TEJAS M                        2,727,356     2,727,356               0            0              0             0            0           0
 SABINE 3                               80,097,500             0      80,097,500            0              0             0            0           0
 SABINE 3/CENTANA#3 E                    1,743,891     1,743,891               0            0              0             0            0           0
 SABINE 3/CENTANA#3 M                   19,610,652    19,607,345               0            0              0             0        2,976         331
 SABINE 3/ENBRIDGE E                     8,334,248     8,334,115               0            0              0             0          133           0
 SABINE 3/ENBRIDGE M                    19,410,359    19,410,307               0            0              0             0           52           0
 SABINE 3/HPL/CH E                       1,473,991     1,473,991               0            0              0             0            0           0
 SABINE 3/STORAGE I                         45,749        45,749               0            0              0             0            0           0
 SABINE 3/TEJAS E                        1,959,750     1,959,750               0            0              0             0            0           0
 SABINE 3/TEJAS M                        6,623,860     6,623,435               0            0              0             0          425           0
 SABINE 4                               76,167,950             0      76,167,950            0              0             0            0           0
 SABINE 4/Aux                             (510,000)     (510,000)              0            0              0             0            0           0
 SABINE 4/CENTANA#3 M                    6,687,645     6,687,645               0            0              0             0            0           0
 SABINE 4/ENBRIDGE E                    20,720,155    20,719,730               0            0              0             0          425           0
 SABINE 4/ENBRIDGE M                    14,655,058    14,655,058               0            0              0             0            0           0
 SABINE 4/HPL/CH E                         791,784       791,784               0            0              0             0            0           0
 SABINE 4/STORAGE I                      9,753,002     9,753,002               0            0              0             0            0           0
 SABINE 4/TEJAS M                        3,690,406     3,690,406               0            0              0             0            0           0
 SABINE 5                               70,933,725             0      70,933,725            0              0             0            0           0
 SABINE 5/CENTANA#3 M                   10,846,322    10,846,314               0            0              0             0            8           0
 SABINE 5/ENBRIDGE E                     3,383,577     3,383,577               0            0              0             0            0           0
 SABINE 5/ENBRIDGE M                     2,780,434     2,780,434               0            0              0             0            0           0
 SABINE 5/HPL/CH E                       1,615,404     1,615,404               0            0              0             0            0           0
 SABINE 5/TEJAS E                        1,374,341     1,374,341               0            0              0             0            0           0
 SABINE 5/TEJAS M                       32,429,197    32,423,416               0            0          5,781             0            0           0
 SAMRAY 1_2/Aux                           (134,000)     (134,000)              0            0              0             0            0           0
 SAMRAY 1_2/HYDRO                        8,333,000     8,333,000               0            0              0             0            0           0
 TOLEDO 1/HYDRO                          2,864,293     2,864,293               0            0              0             0            0           0
 TOWN B 1/HYDRO                          3,105,000     3,105,000               0            0              0             0            0           0
 WILLOW GLEN 1/BL HOLDINGS E             5,445,950     5,291,095               0            0        154,855             0            0           0
 WILLOW GLEN 2/BL HOLDINGS E            10,391,250     8,907,191               0      569,266        912,881             0        1,912           0
 WILLOW GLEN 4/BL HOLDINGS E            77,447,750    77,445,013               0            0              0             0        1,742         995
 INDEPN 1/COAL                           4,757,472     4,757,472               0            0              0             0            0           0
 WH.BLF 1/COAL                           8,755,797     8,755,797               0            0              0             0            0           0
 WH.BLF 2/COAL                           7,368,498     7,368,498               0            0              0             0            0           0
 AECC Excess BAILEY 1                       39,312        39,312               0            0              0             0            0           0
 AECC Excess INDEPN 2                       11,318        11,318               0            0              0             0            0           0
 AECC Excess MCCLEL 1                    2,581,467     2,581,467               0            0              0             0            0           0
 AECC Excess WH.BLF 1                    1,165,458     1,165,458               0            0              0             0            0           0
 AECC Excess WH.BLF 2                    5,690,108     5,690,108               0            0              0             0            0           0
 AECI/WSPP A                               391,495       391,495               0            0              0             0            0           0
 AECI/WSPP B                             3,272,000     3,272,000               0            0              0             0            0           0
 AECI/WSPP C SYSTEM FIRM                 7,537,870     7,445,246               0       43,518         46,531             0        2,575           0
 AEP SERVICE CORP /WSPP A                  490,800       490,800               0            0              0             0            0           0
 AEP SERVICE CORP /WSPP C                  130,880       130,880               0            0              0             0            0           0
 AIR LIQUIDE MAGNOLIA/QF                   202,615       202,615               0            0              0             0            0           0
 AMEREN ENERGY NC. (AE) ACTING             392,640       391,043               0            0              0             0        1,597           0
 Ameren Energy Marketing Company/WSPP        8,180         8,180               0            0              0             0            0           0
 BASF CORPORATION/QF                     4,486,070     4,486,070               0            0              0             0            0           0
 BNP PARIBAS ENERGY TRADING                 32,720        32,720               0            0              0             0            0           0
 BNP PARIBAS ENERGY TRADING                629,696       629,696               0            0              0             0            0           0
 CALP NE ENERGY SERVICES L.P./WSPP       2,185,696     2,173,624               0            0              0             0       12,072           0
 CARGILL POWER MARKETS LLC/WSPP A          274,031       274,031               0            0              0             0            0           0
 CARROLLSTPARK/QF                       91,582,450    91,582,450               0            0              0             0            0           0
 CITIGROUP ENERGY NC/WSPP A                 39,264        39,264               0            0              0             0            0           0
 CLECO/WSPP B                              821,270       742,128               0            0         13,803             0       65,339           0
 CONOCOPH LLIPS COMPANY /INTRA-          1,575,625     1,575,625               0            0              0             0            0           0
 CONSTELLATION ENERGY                       29,448        29,448               0            0              0             0            0           0
 CONSTELLATION ENERGY                      889,493       888,956               0            0              0             0          537           0
 COTTONWOOD ENERGY CO/EXS50                 32,612        32,612               0            0              0             0            0           0
 COTTONWOOD ENERGY CO/EXS75                  7,868         7,868               0            0              0             0            0           0
 COTTONWOOD ENERGY CO/EXS90                343,686       343,686               0            0              0             0            0           0
 COTTONWOOD ENERGY CO/EXSSS50                1,990         1,990               0            0              0             0            0           0
 COTTONWOOD ENERGY CO/EXSSTSH              227,513       227,513               0            0              0             0            0           0
 Attachment Snapshot: 20100826181933                        RunID: 17029                                              Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                            9-178
                                                                                                                         Exhibit PJC-2
                                                                                                                    2011 TX Rate Case
                                                                                                                         Page 17 of 70




 Entergy Electric System                     Date range - 20100701 through 20100731                                                      Attachment 1
 Intra-System Billing-201007RA           KWH Log Sheet Reconciliation - Entergy Texas, Inc                                                    Page 17

                   Company                Net Gen         To Area           UPP         Exchange      Inadvertent    Firm Sales Sys Sales        Unacct

 CYPRES/EXS50                                  3,133           3,133               0             0               0             0           0            0
 CYPRES/EXS75                                    172             172               0             0               0             0           0            0
 CYPRES/EXS90                                 20,708          20,708               0             0               0             0           0            0
 DB ENERGY TRAD NG LLC/WSPP B             16,919,189      16,831,732               0             0               0             0      87,457            0
 DOW P PELINE COMPANY/INTRA-DAY            1,572,500       1,281,171               0       274,685           8,616             0       8,028            0
 DUKE ENERGY HINDS/EXS50                      18,538          18,538               0             0               0             0           0            0
 DUKE ENERGY HINDS/EXS75                      13,524          13,524               0             0               0             0           0            0
 DUKE ENERGY HINDS/EXS90                     141,631         141,631               0             0               0             0           0            0
 DUKEENERGY HOTSPRING/EXS50                   22,927          22,927               0             0               0             0           0            0
 DUKEENERGY HOTSPRING/EXS75                   13,806          13,806               0             0               0             0           0            0
 DUKEENERGY HOTSPRING/EXS90                  119,726         119,726               0             0               0             0           0            0
 DUKEENERGY HOTSPRING/FREE                       123             123               0             0               0             0           0            0
 ENDURE ENERGY/WSPP A                        222,491         221,552               0             0               0             0         939            0
 ENDURE ENERGY/WSPP B                         10,634          10,634               0             0               0             0           0            0
 ENG. CARBONS NC/QF                        2,020,069       2,020,069               0             0               0             0           0            0
 ETEC/WSPP B                                 191,412         191,412               0             0               0             0           0            0
 EXELON GENERATION COMPANY                15,297,742      15,273,636               0             0               0             0      24,106            0
 GOODYEAR TIRE/QF                            577,318         577,318               0             0               0             0           0            0
 HUNTSMAN P.N./QF                             74,401          74,401               0             0               0             0           0            0
 J ARON & COMPANY/WSPP B                   3,905,132       3,895,829               0             0               0             0       9,303            0
 J.P. MORGAN VENTURES ENERGY                  10,961          10,961               0             0               0             0           0            0
 J.P. MORGAN VENTURES ENERGY                 799,186         708,121               0             0               0             0      91,065            0
 JBO/WSPP A                                1,582,176       1,025,309               0        75,631         274,237             0     206,999            0
 JBO/WSPP B                                1,698,984       1,502,028               0       111,406          44,672             0      40,878            0
 KANSAS CITY POWER & LIGHT                   235,748         235,748               0             0               0             0           0            0
 MAGNET COVE/EXS75                             2,777           2,777               0             0               0             0           0            0
 MAGNET COVE/EXS90                           128,521         128,521               0             0               0             0           0            0
 MAGNET COVE/EXSSTSH                         706,713         706,713               0             0               0             0           0            0
 MDEA CROSSROADS/EXS50                         3,797           3,797               0             0               0             0           0            0
 MDEA CROSSROADS/EXS75                           768             768               0             0               0             0           0            0
 MDEA CROSSROADS/EXS90                        26,848          26,848               0             0               0             0           0            0
 MERRILL LYNCH COMMODITIES                31,749,681      31,568,580               0             0               0             0     181,101            0
 MORGAN STANLEY/WSPP A                        40,246          40,246               0             0               0             0           0            0
 NRG CAJUN 3/CAJUN 3                      70,923,575      70,923,575               0             0               0             0           0            0
 NRG POWER MARKETING LLC./WSPP A           4,871,190       4,638,871               0       225,360           6,959             0           0            0
 NRG POWER MARKETING LLC./WSPP B          30,247,034      29,856,229               0             0          87,663             0     303,142            0
 NRG POWER MARKETING LLC./WSPP C           1,363,606       1,353,747               0             0           4,971             0       4,888            0
 OCCIDENTAL POWER SERVICES/WSPP              932,192         828,673               0        32,720          19,494             0      51,305            0
 PREMCR/QF                                   376,760         376,760               0             0               0             0           0            0
 RAINBOW ENERGY MARKETING                  2,277,962       2,277,962               0             0               0             0           0            0
 SABINE COGEN L P./QF                     35,724,878      35,724,878               0             0               0             0           0            0
 SMEPA/WSPP B                                490,800         310,404               0       167,697           8,616             0       4,083            0
 SOUTHERN COMPANY SERVICES INC.               89,980          89,980               0             0               0             0           0            0
 SOUTHERN COMPANY SERVICES INC.            1,734,160       1,111,805               0       322,527          79,204             0     220,624            0
 SRW COGENERATION/QF                      49,808,910      49,808,910               0             0               0             0           0            0
 SUEZ Energy Marketing NA Inc./WSPP A      1,416,776       1,416,776               0             0               0             0           0            0
 SUEZ Energy Marketing NA Inc./WSPP B      9,249,460       9,199,959               0             0               0             0      49,501            0
 TEA/WSPP A                                  182,578         182,578               0             0               0             0           0            0
 TENASKA FRONTIER/EXS50                       13,439          13,439               0             0               0             0           0            0
 TENASKA FRONTIER/EXS75                       10,544          10,544               0             0               0             0           0            0
 TENASKA FRONTIER/EXS90                      170,975         170,975               0             0               0             0           0            0
 TENASKA/WSPP A                              384,624         364,212               0        15,456               0             0       4,956            0
 TENASKA/WSPP B                            3,770,813       3,682,588               0             0          63,999             0      24,226            0
 UNION POWER PARTNERS/WSPP A                  31,084          31,084               0             0               0             0           0            0
 UNION POWER PARTNERS/WSPP B              26,950,968      26,841,101               0             0               0             0     109,867            0
 Un-accounted In                               3,203           3,203               0             0               0             0           0            0
 WESTAR ENERGY NC/WSPP A                   1,134,394       1,134,394               0             0               0             0           0            0
 WESTAR ENERGY NC/WSPP B                   4,834,398       4,832,588               0             0               0             0       1,810            0
 WESTAR ENERGY NC/WSPP C                     130,880         130,880               0             0               0             0           0            0
 WRIGHTSVILE POWER/EXS75                       6,069           6,069               0             0               0             0           0            0
 WRIGHTSVILE POWER/EXS90                     133,010         133,010               0             0               0             0           0            0
 YAZOO CITY/EXS90                                863             863               0             0               0             0           0            0
 Exchange                                328,392,353     327,900,434               0             0         490,923             0           0          996
 INADVERTENT N                             2,504,716       2,504,716               0             0               0             0           0            0

 Totals                                 2,373,774,114   1,913,442,261     452,849,875     2,259,218      3,628,651             0   1,590,958        3,151




 Attachment Snapshot: 20100826181933                             RunID: 17029                                               Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                                  9-179
                                                                                                                                 Exhibit PJC-2
                                                                                                                            2011 TX Rate Case
                                                                                                                                 Page 18 of 70




 Entergy Electric System                                Date range - 20100701 through 20100731                                                    Attachment 1
 Intra-System Billing-201007RA                                  KWH Energy Summary                                                                     Page 18

    Company             Net Gen          To Area            UPP            Exchange        Inadvertent     Firm Sales        System Sales         Unaccounted

 AR                   3,068,221,822     2,534,515,289      395,462,556       131,743,223       4,583,474                0           1,913,306                3,974
 LA                   3,491,820,106     3,093,813,592      254,622,820       135,105,357       5,498,856                0           2,774,712                4,769
 MS                   1,669,714,232     1,633,071,080                0        32,027,550       3,063,696                0           1,549,246                2,660
 NO                     587,352,718       554,353,844                0        31,587,544         978,872                0             431,606                  852
 EGSL                 3,103,786,681     2,038,635,428      670,461,007       388,628,993       4,145,451                0           1,912,208                3,594
 ETI                  2,373,774,114     1,913,442,261      452,849,875         2,259,218       3,628,651                0           1,590,958                3,151

 Totals              14,294,669,673    11,767,831,494    1,773,396,258       721,351,885      21,899,000                0       10,172,036                  19,000




 Attachment Snapshot: 20100826181933                                     RunID: 17029                                                Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                                          9-180
                                                                                                               Exhibit PJC-2
                                                                                                          2011 TX Rate Case
                                                                                                               Page 19 of 70




 Entergy Electric System                Date range - 20100701 through 20100731                                                   Attachment 1
 Intra-System Billing-201007RA              Joint Account Purchases - KWH                                                             Page 19

                         Description           System              AR          LA           MS           NO            EGSL              ETI

 AECI/WSPP A                                      2,393,000        499,659      601,840      333,584      108,163       458,259          391,495
 AECI/WSPP B                                     20,000,000      4,176,000    5,030,000    2,788,000      904,000     3,830,000        3,272,000
 AECI/WSPP C SYSTEM FIRM                         46,075,000      9,620,460   11,587,863    6,422,855    2,082,590     8,823,362        7,537,870
 AEP SERVICE CORP /WSPP A                         3,000,000        626,400      754,500      418,200      135,600       574,500          490,800
 AEP SERVICE CORP /WSPP C                           800,000        167,040      201,200      111,520       36,160       153,200          130,880
 AMEREN ENERGY NC. (AE) ACTING /WSPP C            2,400,000        501,120      603,600      334,560      108,480       459,600          392,640
 AMEREN ENERGY MARKETING COMPANY/WSPP A              50,000         10,440       12,575        6,970        2,260         9,575            8,180
 BNP PARIBAS ENERGY TRADING GP/WSPP A               200,000         41,760       50,300       27,880        9,040        38,300           32,720
 BNP PARIBAS ENERGY TRADING GP/WSPP B             3,849,000        803,671      968,024      536,551      173,975       737,083          629,696
 CALP NE ENERGY SERVICES L.P./WSPP B             13,360,000      2,789,568    3,360,048    1,862,384      603,872     2,558,432        2,185,696
 CARGILL POWER MARKETS LLC/WSPP A                 1,675,000        349,740      421,265      233,494       75,710       320,760          274,031
 CITIGROUP ENERGY NC/WSPP A                         240,000         50,112       60,361       33,456       10,848        45,959           39,264
 CLECO/WSPP B                                     5,020,000      1,048,172    1,262,618      699,790      226,908       961,242          821,270
 CONSTELLATION ENERGY COMMODITIES GROUP             180,000         37,584       45,271       25,092        8,136        34,469           29,448
 CONSTELLATION ENERGY COMMODITIES GROUP           5,437,000      1,135,245    1,367,406      757,918      245,753     1,041,185          889,493
 COTTONWOOD ENERGY CO/EXS50                         199,330         41,619       50,135       27,787        9,005        38,172           32,612
 COTTONWOOD ENERGY CO/EXS75                          48,097         10,037       12,102        6,703        2,169         9,218            7,868
 COTTONWOOD ENERGY CO/EXS90                       2,100,765        438,669      528,321      292,830       94,934       402,325          343,686
 COTTONWOOD ENERGY CO/EXSSS50                        12,167          2,541        3,060        1,696          550         2,330            1,990
 COTTONWOOD ENERGY CO/EXSSTSH                     1,390,663        290,367      349,743      193,858       62,864       266,318          227,513
 CYPRES/EXS50                                        19,150          3,999        4,816        2,669          866         3,667            3,133
 CYPRES/EXS75                                         1,050            219          264          146           48           201              172
 CYPRES/EXS90                                       126,581         26,430       31,833       17,648        5,724        24,238           20,708
 DB ENERGY TRAD NG LLC/WSPP B                   103,418,000     21,593,680   26,009,688   14,416,465    4,674,492    19,804,486       16,919,189
 DUKE ENERGY HINDS/EXS50                            113,319         23,661       28,499       15,797        5,123        21,701           18,538
 DUKE ENERGY HINDS/EXS75                             82,677         17,266       20,807       11,523        3,726        15,831           13,524
 DUKE ENERGY HINDS/EXS90                            865,808        180,827      217,804      120,648       39,071       165,827          141,631
 DUKEENERGY HOTSPRING/EXS50                         140,174         29,273       35,260       19,538        6,334        26,842           22,927
 DUKEENERGY HOTSPRING/EXS75                          84,365         17,619       21,226       11,762        3,804        16,148           13,806
 DUKEENERGY HOTSPRING/EXS90                         731,601        152,741      183,983      101,969       33,061       140,121          119,726
 DUKEENERGY HOTSPRING/FREE                              750            156          189          105           33           144              123
 ENDURE ENERGY/WSPP A                             1,360,000        283,965      342,048      189,589       61,475       260,432          222,491
 ENDURE ENERGY/WSPP B                                65,000         13,572       16,348        9,061        2,938        12,447           10,634
 ETEC/WSPP B                                      1,170,000        244,298      294,260      163,098       52,882       224,050          191,412
 EXELON GENERATION COMPANY LLC/DA LY CALL        93,507,000     19,524,239   23,517,077   13,034,879    4,226,539    17,906,524       15,297,742
 J ARON & COMPANY/WSPP B                         23,870,000      4,984,056    6,003,359    3,327,478    1,078,924     4,571,051        3,905,132
 J.P. MORGAN VENTURES ENERGY                         67,000         13,990       16,851        9,340        3,028        12,830           10,961
 J.P. MORGAN VENTURES ENERGY                      4,885,000      1,019,989    1,228,582      680,969      220,801       935,473          799,186
 JBO/WSPP A                                       9,671,000      2,019,305    2,432,270    1,348,137      437,129     1,851,983        1,582,176
 JBO/WSPP B                                      10,385,000      2,168,386    2,611,868    1,447,671      469,404     1,988,687        1,698,984
 KANSAS CITY POWER & LIGHT COMPANY/WSPP A         1,441,000        300,881      362,411      200,875       65,133       275,952          235,748
 MAGNET COVE/EXS75                                   16,976          3,545        4,270        2,366          767         3,251            2,777
 MAGNET COVE/EXS90                                  785,651        164,007      197,598      109,555       35,498       150,472          128,521
 MAGNET COVE/EXSSTSH                              4,319,727        901,963    1,086,406      602,169      195,248       827,228          706,713
 MDEA CROSSROADS/EXS50                               23,211          4,846        5,838        3,235        1,052         4,443            3,797
 MDEA CROSSROADS/EXS75                                4,684            977        1,178          653          212           896              768
 MDEA CROSSROADS/EXS90                              164,075         34,261       41,256       22,867        7,416        31,427           26,848
 MERRILL LYNCH COMMODITIES INC/WSPP B           194,069,000     40,521,612   48,808,429   27,053,226    8,771,914    37,164,138       31,749,681
 MORGAN STANLEY/WSPP A                              246,000         51,366       61,868       34,292       11,118        47,110           40,246
 NRG POWER MARKETING LLC./WSPP A                 29,775,000      6,217,020    7,488,413    4,150,635    1,345,830     5,701,912        4,871,190
 NRG POWER MARKETING LLC./WSPP B                184,884,000     38,603,785   46,498,600   25,772,818    8,356,751    35,405,012       30,247,034
 NRG POWER MARKETING LLC./WSPP C                  8,335,000      1,740,348    2,096,255    1,161,899      376,742     1,596,150        1,363,606
 OCCIDENTAL POWER SERVICES/WSPP B                 5,698,000      1,189,742    1,433,048      794,302      257,550     1,091,166          932,192
 RAINBOW ENERGY MARKETING CORP/WSPP A            13,924,000      2,907,333    3,501,908    1,941,010      629,363     2,666,424        2,277,962
 SMEPA/WSPP B                                     3,000,000        626,400      754,504      418,200      135,600       574,496          490,800
 SOUTHERN COMPANY SERVICES INC. AS AGENT            550,000        114,840      138,325       76,670       24,860       105,325           89,980
 SOUTHERN COMPANY SERVICES INC. AS AGENT         10,600,000      2,213,280    2,665,900    1,477,640      479,120     2,029,900        1,734,160
 SUEZ ENERGY MARKETING NA NC /WSPP A              8,660,000      1,808,208    2,178,009    1,207,204      391,432     1,658,371        1,416,776
 SUEZ ENERGY MARKETING NA NC /WSPP B             56,537,000     11,804,928   14,219,068    7,881,251    2,555,470    10,826,823        9,249,460
 TEA/WSPP A                                       1,116,000        233,021      280,677      155,570       50,443       213,711          182,578
 TENASKA FRONTIER/EXS50                              82,147         17,152       20,660       11,451        3,714        15,731           13,439
 TENASKA FRONTIER/EXS75                              64,452         13,458       16,210        8,985        2,912        12,343           10,544
 TENASKA FRONTIER/EXS90                           1,045,147        218,226      262,868      145,651       47,232       200,195          170,975
 TENASKA/WSPP A                                   2,351,000        490,888      591,278      327,729      106,266       450,215          384,624
 TENASKA/WSPP B                                  23,049,000      4,812,638    5,796,845    3,213,034    1,041,808     4,413,862        3,770,813
 UNION POWER PARTNERS/WSPP A                        190,000         39,672       47,786       26,486        8,588        36,384           31,084
 UNION POWER PARTNERS/WSPP B                    164,737,000     34,397,079   41,431,444   22,964,343    7,446,119    31,547,047       26,950,968
 WESTAR ENERGY NC/WSPP A                          6,934,000      1,447,817    1,743,909      966,608      313,419     1,327,853        1,134,394
 WESTAR ENERGY NC/WSPP B                         29,550,000      6,170,038    7,431,833    4,119,252    1,335,662     5,658,817        4,834,398
 WESTAR ENERGY NC/WSPP C                            800,000        167,040      201,200      111,520       36,160       153,200          130,880
 WRIGHTSVILE POWER/EXS75                             37,100          7,745        9,333        5,171        1,675         7,107            6,069
 WRIGHTSVILE POWER/EXS90                            813,136        169,805      204,509      113,362       36,734       155,716          133,010
 YAZOO CITY/EXS90                                     5,270          1,101        1,324          734          237         1,011              863

 Totals                                        1,112,801,073 232,352,897 279,870,424 155,124,383       50,298,464 213,100,660 182,054,245
 Attachment Snapshot: 20100826181933                    RunID: 17029                                                Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                       9-181
                                                                                                             Exhibit PJC-2
                                                                                                        2011 TX Rate Case
                                                                                                             Page 20 of 70




 Entergy Electric System                 Date range - 20100701 through 20100731                                             Attachment 1
 Intra-System Billing-201007RA            Individual Company Purchases - KWH                                                     Page 20

                         Description            System              AR         LA         MS           NO         EGSL              ETI

 ACADIA POWER PARTNERS, LLC/WSPP B               179,125,000             0 179,125,000          0             0           0               0
 BURAS TEMP                                          131,908             0     131,908          0             0           0               0
 CALP NE A BASE IN                               137,098,200             0           0          0             0 137,098,200               0
 CALP NE B BASE IN                                98,223,400             0           0          0             0 98,223,400                0
 CALP NE C BASE IN                                 5,787,100             0           0          0             0   5,787,100               0
 CALP NE B RAMP IN                                 1,973,300             0           0          0             0   1,973,300               0
 CALP NE C RAMP IN                                    34,100             0           0          0             0      34,100               0
 CALP NE EXCESS N                                    422,000             0           0          0             0     422,000               0
 CONOCOPH LLIPS COMPANY /INTRA-DAY CALL            3,425,000             0           0          0             0   1,969,375       1,455,625
 CONOCOPH LLIPS COMPANY /INTRA-DAY CALL              120,000             0           0          0             0           0         120,000
 DOW P PELINE COMPANY/INTRA-DAY CALL OPTION        3,700,000             0           0          0             0   2,127,500       1,572,500
 EPI-ISES ELI   IN                                35,090,137             0 35,090,137           0             0           0               0
 EPI-ISES ENOI IN                                 34,395,193             0           0          0    34,395,193           0               0
 ETEC EXCESS-HRSNHRDN                                  4,937             0           0          0             0           0           4,937
 EXELON FRONT ER 10YR                             93,424,000             0           0          0             0           0      93,424,000
 HARDIN                                            9,029,000             0           0          0             0           0       9,029,000
 MEAM CANTON 1 IN                                     73,000             0           0     73,000             0           0               0
 MEAM CANTON 2 IN                                     83,000             0           0     83,000             0           0               0
 MEAM CANTON 3 IN                                     84,000             0           0     84,000             0           0               0
 MEAM CANTON 4 IN                                     84,000             0           0     84,000             0           0               0
 MEAM CANTON 5 IN                                     82,000             0           0     82,000             0           0               0
 MEAM HENDERSON 10 IN                                 58,000             0           0     58,000             0           0               0
 MEAM HENDERSON 11 IN                                 59,000             0           0     59,000             0           0               0
 MEAM HENDERSON 2 IN                                 524,000             0           0    524,000             0           0               0
 MEAM HENDERSON 4 IN                                  72,000             0           0     72,000             0           0               0
 MEAM HENDERSON 5 IN                                  72,000             0           0     72,000             0           0               0
 MEAM HENDERSON 6 IN                                  73,000             0           0     73,000             0           0               0
 MEAM HENDERSON 7 IN                                  76,000             0           0     76,000             0           0               0
 MEAM HENDERSON 8 IN                                  74,000             0           0     74,000             0           0               0
 MEAM HENDERSON 9 IN                                  54,000             0           0     54,000             0           0               0
 OCCIDENTAL POWER SERVICES/BASE CAPACITY         219,380,000             0 219,380,000          0             0           0               0
 OCCIDENTAL POWER SERVICES/DAY-AHEAD CALL         50,188,000             0 50,188,000           0             0           0               0
 OCCIDENTAL POWER SERVICES/ NTRA-DAY CALL          9,090,000             0   9,090,000          0             0           0               0
 SAN JACINTO 1                                     5,722,000             0           0          0             0           0       5,722,000
 SAN JACINTO 2                                     5,612,000             0           0          0             0           0       5,612,000

 Totals                                          893,443,275             0 493,005,045   1,468,000   34,395,193 247,634,975 116,940,062




 Attachment Snapshot: 20100826181933                     RunID: 17029                                          Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                     9-182
                                                                                                                     Exhibit PJC-2
                                                                                                                2011 TX Rate Case
                                                                                                                     Page 21 of 70




 Entergy Electric System                          Date range - 20100701 through 20100731                                             Attachment 2
 Intra-System Billing-201007RA                Energy Sold to Exchange - Entergy Arkansas, Inc.                                            Page 21

                                            Source                              KWH           Mills per KWH    Cost

                            AECC Excess BAILEY 1                                     30,723        59.282297       1,821.33
                            AECC Excess INDEPN 2                                     14,445        21.739702         314.03
                            AECC Excess MCCLEL 1                                    952,753        61.531173      58,624.01
                            AECC Excess WH.BLF 1                                    914,776        21.867474      20,003.84
                            AECC Excess WH.BLF 2                                  3,188,988        22.097709      70,469.33
                            AECI/WSPP A                                             275,334        26.304343       7,242.48
                            AECI/WSPP B                                             783,000        38.000000      29,754.00
                            AECI/WSPP C SYSTEM FIRM                               2,837,035        34.875139      98,941.99
                            AEP SERVICE CORP /WSPP A                                254,973        29.310241       7,473.32
                            AEP SERVICE CORP /WSPP C                                 10,440        49.000000         511.56
                            AMEREN ENERGY INC. (AE) ACTING /WSPP C                  145,951        30.098663       4,392.93
                            BNP PARIBAS ENERGY TRADING GP/WSPP B                     33,408        52.000120       1,737.22
                            CALP NE ENERGY SERVICES L.P./WSPP B                     236,639        53.867663      12,747.19
                            CITIGROUP ENERGY INC/WSPP A                              10,440        29.000000         302.76
                            CLECO/WSPP B                                            317,798        63.178623      20,078.04
                            CONSTELLATION ENERGY COMMODITIES                        204,354        39.196982       8,010.06
                            COTTONWOOD ENERGY CO/EXS50                                7,619        22.040950         167.93
                            COTTONWOOD ENERGY CO/EXS75                                2,111        30.127901          63.60
                            COTTONWOOD ENERGY CO/EXS90                               51,457        35.798434       1,842.08
                            COTTONWOOD ENERGY CO/EXSSTSH                             80,914        37.536026       3,037.19
                            COUCH 2/CEGT E                                        9,781,627        75.576540     739,261.52
                            COUCH 2/CENTERPOINT I                                    17,362        70.389356       1,222.10
                            CROSS O L/QF                                             76,886        37.393414       2,875.03
                            DB ENERGY TRAD NG LLC/WSPP B                          2,901,191        51.582105     149,649.54
                            DUKE ENERGY HINDS/EXS75                                   5,582        29.681118         165.68
                            DUKE ENERGY HINDS/EXS90                                  11,889        37.935066         451.01
                            DUKEENERGY HOTSPRING/EXS50                                   20        22.000000           0.44
                            DUKEENERGY HOTSPRING/EXS75                                  700        29.671429          20.77
                            DUKEENERGY HOTSPRING/EXS90                                2,264        39.553887          89.55
                            ENDURE ENERGY/WSPP B                                     13,572        26.000589         352.88
                            EXELON GENERATION COMPANY LLC/DA LY                   4,361,740        39.438912     172,022.28
                            J ARON & COMPANY/WSPP B                                 599,915        50.452247      30,267.06
                            JBO/WSPP A                                              217,449        71.165607      15,474.89
                            JBO/WSPP B                                              275,382        48.699370      13,410.93
                            JONESBORO Excess INDEPN 2                             1,221,922        24.163605      29,526.04
                            JONESBORO Excess WH BLF 1                             1,744,400        24.848733      43,346.13
                            JONESBORO Excess WH BLF 2                             2,670,122        25.411835      67,852.70
                            L.CATH 4/CEGT E                                       7,839,611        58.044036     455,042.66
                            L.CATH 4/CENTERPOINT I                                1,399,984        57.172289      80,040.29
                            LYNCH 3/CEGT E                                        2,936,490        74.911340     219,976.40
                            LYNCH 3/CENTERPOINT I                                   659,947        70.499298      46,525.80
                            LYNCH IC/#2 OIL                                           2,000       159.310000         318.62
                            MABELV T/CEGT E                                           2,000        77.685000         155.37
                            MAGNET COVE/EXS90                                        35,561        34.416636       1,223.89
                            MAGNET COVE/EXSSTSH                                     344,998        35.709888      12,319.84
                            MERRILL LYNCH COMMODITIES INC/WSPP B                  5,621,170        44.051592     247,621.49
                            MORGAN STANLEY/WSPP A                                    21,507        22.999954         494.66
                            NRG POWER MARKETING LLC./WSPP A                       2,773,777        23.000003      63,796.88
                            NRG POWER MARKETING LLC./WSPP B                       4,613,037        53.167872     245,265.36
                            NRG POWER MARKETING LLC./WSPP C                         212,817        40.363881       8,590.12
                            OCCIDENTAL POWER SERVICES/WSPP B                        241,196        63.464402      15,307.36
                            OUACHITA 1/SIGCO I                                      234,880        41.043256       9,640.24
                            OUACHITA 1/SIGPL E                                    3,527,779        38.975406     137,496.62
                            OUACHITA 2/SIGPL E                                      910,452        37.911828      34,516.90
                            PINE BLUFF ENERGY/QF                                 31,414,407        37.351724   1,173,382.27
                            RAINBOW ENERGY MARKETING CORP/WSPP A                    154,939        39.856524       6,175.33
                            SOUTHERN COMPANY SERVICES INC. AS                        62,640        38.000000       2,380.32
                            SUEZ Energy Marketing NA Inc./WSPP A                    177,491        37.581568       6,670.39
                            SUEZ Energy Marketing NA Inc./WSPP B                  1,049,490        44.543045      46,747.48
                            TEA/WSPP A                                               28,188        23.110898         651.45
                            TENASKA FRONTIER/EXS75                                    3,670        31.572207         115.87
                            TENASKA FRONTIER/EXS90                                   40,595        34.643183       1,406.34
                            TENASKA/WSPP B                                          449,719        62.669200      28,183.53
                            UNION POWER PARTNERS/WSPP A                               3,576        35.000000         125.16
                            UNION POWER PARTNERS/WSPP B                           3,127,518        48.726594     152,393.30
                            WESTAR ENERGY INC/WSPP A                                420,854        29.662876      12,483.74
                            WESTAR ENERGY INC/WSPP B                              1,228,584        36.666341      45,047.68
                            WESTAR ENERGY INC/WSPP C                                 10,440        62.000000         647.28
                            WH.BLF 1/COAL                                        25,833,205        21.377925     552,260.31
                            WH.BLF 2/COAL                                         2,103,620        21.350173      44,912.65
                            WRIGHTSVILE POWER/EXS90                                   1,900        35.321053          67.11

                            Totals                                              131,743,223        39.967947   5,265,506.15



 Attachment Snapshot: 20100826181933                             RunID: 17029                                           Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                             9-183
                                                                                                                     Exhibit PJC-2
                                                                                                                2011 TX Rate Case
                                                                                                                     Page 22 of 70




 Entergy Electric System                         Date range - 20100701 through 20100731                                              Attachment 2
 Intra-System Billing-201007RA               Energy Sold to Exchange - Entergy Louisiana, LLC                                             Page 22

                                            Source                             KWH           Mills per KWH     Cost

                            AECC Excess MCCLEL 1                                   126,981        61.531095        7,813.28
                            AECI/WSPP C SYSTEM FIRM                                678,098        66.741784       45,257.47
                            BURAS TEMP                                              45,238       260.515054       11,785.18
                            CLECO/WSPP B                                           132,197        71.855337        9,499.06
                            ENDURE ENERGY/WSPP A                                    24,396        68.000082        1,658.93
                            J ARON & COMPANY/WSPP B                                126,465        69.758668        8,822.03
                            J.P. MORGAN VENTURES ENERGY                             38,670        68.000000        2,629.56
                            JBO/WSPP A                                           1,258,817        71.820749       90,409.18
                            JBO/WSPP B                                             262,779        73.000049       19,182.88
                            L.GPSY 1/EVANG(LT) M                                 7,913,583        65.067524      514,917.25
                            L.GPSY 1/EVG/CG I                                       46,349        62.358627        2,890.26
                            L.GPSY 2/BRDGLN E                                    1,045,351        72.682793       75,979.03
                            L.GPSY 2/CGT M                                          25,995        69.795730        1,814.34
                            L.GPSY 2/EVANG(LT) M                                25,320,605        76.863691    1,946,235.15
                            L.GPSY 2/EVG/CG I                                    2,135,948        77.639226      165,833.35
                            L.GPSY 2/GSPL M                                        346,715        71.005754       24,618.76
                            L.GPSY 3/EVANG(LT) M                                 2,662,097        61.674045      164,182.29
                            N NEMI 3/EVANG(LT) M                                 5,982,602        78.343928      468,700.54
                            N NEMI 3/EVG/CG I                                      905,754        79.255449       71,785.94
                            N NEMI 4/EVANG(LT) M                                 3,228,244        63.765917      205,851.94
                            N NEMI 4/EVG/CG I                                        1,224        61.078431           74.76
                            N NEMI 5/EVANG(LT) M                                 1,193,561        60.638794       72,376.10
                            NRG POWER MARKETING LLC./WSPP A                        377,250        84.000000       31,689.00
                            NRG POWER MARKETING LLC./WSPP B                        500,863        78.088499       39,111.64
                            NRG POWER MARKETING LLC./WSPP C                         25,150        65.000000        1,634.75
                            OCCIDENTAL POWER SERVICES/WSPP B                        49,866        65.000000        3,241.29
                            SMEPA/WSPP B                                           748,227        89.186383       66,731.66
                            SOUTHERN COMPANY SERVICES INC. AS                    2,326,731       127.999992      297,821.55
                            TENASKA/WSPP B                                         361,244        66.072654       23,868.35
                            WATERF 1/BRDGLN E                                      843,299        73.709028       62,158.75
                            WATERF 1/CGT M                                         356,988        72.433695       25,857.96
                            WATERF 1/EVANG(LT) M                                47,727,893        79.757661    3,806,665.12
                            WATERF 1/EVG/CG I                                    3,677,054        79.147478      291,029.55
                            WATERF 2/#6 OIL                                        302,500       121.708562       36,816.84
                            WATERF 2/BRDGLN E                                    9,002,954        66.117939      595,256.76
                            WATERF 2/CGT E                                       1,648,800        64.400734      106,183.93
                            WATERF 2/CGT M                                       8,938,269        65.179773      582,594.34
                            WATERF 2/EVANG(LT) M                                 3,286,637        71.768790      235,877.96
                            WATERF 2/EVG/CG I                                    1,383,963        69.682672       96,438.24
                            WATERF 4/#2 OIL                                         46,000       236.132391       10,862.09

                            Totals                                             135,105,357        75.690241   10,226,157.06




 Attachment Snapshot: 20100826181933                            RunID: 17029                                            Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                             9-184
                                                                                                                   Exhibit PJC-2
                                                                                                              2011 TX Rate Case
                                                                                                                   Page 23 of 70




 Entergy Electric System                         Date range - 20100701 through 20100731                                            Attachment 2
 Intra-System Billing-201007RA              Energy Sold to Exchange - Entergy Mississippi, Inc.                                         Page 23

                                            Source                             KWH          Mills per KWH    Cost

                            AECC Excess BAILEY 1                                      417        59.280576          24.72
                            AECC Excess MCCLEL 1                                  114,704        61.529851       7,057.72
                            ANDRUS 1/TENN E                                     2,659,523        59.401915     157,980.76
                            ANDRUS 1/TENN I                                       716,204        63.247231      45,297.92
                            ANDRUS 1/TGT E                                        500,938        59.031856      29,571.30
                            B.WLSN 1/COLUMBIA ML E                                 38,457        55.997348       2,153.49
                            B.WLSN 2/COLUMBIA MAINLINE I                          137,442        62.881579       8,642.57
                            B.WLSN 2/COLUMBIA ML E                             21,706,585        60.407527   1,311,241.12
                            CLECO/WSPP B                                           97,617        62.407368       6,092.02
                            J ARON & COMPANY/WSPP B                                83,328        59.500048       4,958.02
                            JBO/WSPP A                                             23,631        70.000000       1,654.17
                            JBO/WSPP B                                             90,177        72.999989       6,582.92
                            NRG POWER MARKETING LLC./WSPP B                        57,038        62.625267       3,572.02
                            OCCIDENTAL POWER SERVICES/WSPP B                       54,861        64.510490       3,539.11
                            REX BR 4/GSPL E                                     5,393,054        80.026983     431,589.84
                            REX BR 4/GSPL I                                       201,384        84.433470      17,003.55
                            TENASKA/WSPP A                                          5,820        63.049828         366.95
                            TENASKA/WSPP B                                        146,370        62.000000       9,074.94

                            Totals                                             32,027,550        63.895088   2,046,403.14




 Attachment Snapshot: 20100826181933                            RunID: 17029                                          Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                           9-185
                                                                                                                     Exhibit PJC-2
                                                                                                                2011 TX Rate Case
                                                                                                                     Page 24 of 70




 Entergy Electric System                          Date range - 20100701 through 20100731                                             Attachment 2
 Intra-System Billing-201007RA               Energy Sold to Exchange - Entergy New Orleans, Inc.                                          Page 24

                                             Source                              KWH          Mills per KWH    Cost

                            AECC Excess BAILEY 1                                        980        59.336735         58.15
                            AECC Excess MCCLEL 1                                    315,602        61.530789     19,419.24
                            AECI/WSPP C SYSTEM FIRM                                 608,021        64.528742     39,234.83
                            AMEREN ENERGY INC. (AE) ACTING /WSPP C                   18,080        61.000000      1,102.88
                            BNP PARIBAS ENERGY TRADING GP/WSPP B                     38,354        60.000000      2,301.24
                            CLECO/WSPP B                                             76,004        65.476159      4,976.45
                            DB ENERGY TRAD NG LLC/WSPP B                             95,558        60.088742      5,741.96
                            ENDURE ENERGY/WSPP A                                      8,272        68.000484        562.50
                            J ARON & COMPANY/WSPP B                                 213,035        63.098599     13,442.21
                            J.P. MORGAN VENTURES ENERGY                              34,369        67.999942      2,337.09
                            JBO/WSPP A                                              268,090        72.038718     19,312.86
                            JBO/WSPP B                                              217,346        72.039283     15,657.45
                            MICHOD 2/BRDGLN E                                        62,252        56.774722      3,534.34
                            MICHOD 3/BRDGLN E                                    11,056,337        60.606405    670,084.84
                            MICHOD 3/GSPL E                                      11,458,320        59.604617    682,968.77
                            MICHOD 3/NOPSI I                                      5,187,011        61.884854    320,997.42
                            MICHOD 3/SIGPL E                                        337,959        59.764912     20,198.09
                            NRG POWER MARKETING LLC./WSPP A                          67,800        84.000000      5,695.20
                            NRG POWER MARKETING LLC./WSPP B                         280,383        65.790544     18,446.55
                            NRG POWER MARKETING LLC./WSPP C                          70,969        65.000070      4,612.99
                            OCCIDENTAL POWER SERVICES/WSPP B                         40,184        66.828588      2,685.44
                            SMEPA/WSPP B                                            134,472        89.186745     11,993.12
                            SOUTHERN COMPANY SERVICES INC. AS                       418,166       127.999981     53,525.24
                            TENASKA/WSPP B                                          554,729        64.464883     35,760.54
                            WESTAR ENERGY INC/WSPP C                                 25,251        61.999921      1,565.56

                            Totals                                               31,587,544        61.929948   1,956,214.96




 Attachment Snapshot: 20100826181933                              RunID: 17029                                          Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                             9-186
                                                                                                                    Exhibit PJC-2
                                                                                                               2011 TX Rate Case
                                                                                                                    Page 25 of 70




 Entergy Electric System                          Date range - 20100701 through 20100731                                            Attachment 2
 Intra-System Billing-201007RA          Energy Sold to Exchange - Entergy Gulf States Louisiana, LLC                                     Page 25

                                            Source                              KWH          Mills per KWH    Cost

                            AECC Excess BAILEY 1                                    24,335        59.272242       1,442.39
                            AECC Excess MCCLEL 1                                 2,792,163        61.531042     171,804.70
                            AECI/WSPP C SYSTEM FIRM                              3,173,844        63.794610     202,474.14
                            AGRILECTRIC/QF                                          12,709        44.799748         569.36
                            AMEREN ENERGY INC. (AE) ACTING /WSPP C                 304,529        61.000003      18,576.27
                            BNP PARIBAS ENERGY TRADING GP/WSPP B                    61,280        60.000000       3,676.80
                            CALCAS EU 1/GSPL E                                   3,714,474        59.468127     220,892.81
                            CALCAS EU 1/GSPL I                                     548,116        61.952069      33,956.92
                            CALCAS EU 2/GSPL E                                   2,906,170        59.035428     171,566.99
                            CALP NE B BASE IN                                       71,559        38.740759       2,772.25
                            CALP NE ENERGY SERVICES L.P./WSPP B                    193,011        54.830346      10,582.86
                            CLECO/WSPP B                                           830,943        63.194395      52,510.94
                            CONOCOPH LLIPS COMPANY /INTRA-DAY CALL               1,681,875        60.305136     101,425.70
                            DB ENERGY TRAD NG LLC/WSPP B                         1,654,147        57.964353      95,881.56
                            DOW CHEMICAL/QF                                        123,788        44.948056       5,564.03
                            DOW P PELINE COMPANY/INTRA-DAY CALL                  2,116,638        62.456778     132,198.39
                            ENDURE ENERGY/WSPP A                                    35,043        67.999600       2,382.91
                            EXELON GENERATION COMPANY LLC/DA LY                     53,551        42.891449       2,296.88
                            J ARON & COMPANY/WSPP B                              2,095,052        62.638798     131,231.54
                            J.P. MORGAN VENTURES ENERGY                            828,870        68.000024      56,363.18
                            JBO/WSPP A                                           1,609,650        71.438574     114,991.10
                            JBO/WSPP B                                           1,137,518        70.893981      80,643.18
                            LEWIS CREEK 1/COPANO E                               1,879,528        56.584988     106,353.07
                            LEWIS CREEK 1/COPANO M                              10,925,536        57.084223     623,675.73
                            LEWIS CREEK 1/TETCO E                                1,521,741        55.948581      85,139.25
                            LEWIS CREEK 1/TETCO I                                1,157,040        56.793741      65,712.63
                            LEWIS CREEK 1/TETCO M                                3,647,410        56.295626     205,333.23
                            LEWIS CREEK 2/COPANO E                                 926,721        55.342859      51,287.39
                            LEWIS CREEK 2/COPANO M                               3,483,050        56.566756     197,024.84
                            LEWIS CREEK 2/TEJAS E                                  141,822        54.865254       7,781.10
                            LEWIS CREEK 2/TETCO E                                1,536,278        55.145833      84,719.33
                            LEWIS CREEK 2/TETCO I                                1,582,353        54.986530      87,008.10
                            LEWIS CREEK 2/TETCO M                                5,315,248        55.780833     296,488.96
                            MERRILL LYNCH COMMODITIES INC/WSPP B                   513,751        52.752150      27,101.47
                            NELSON 3/TARGA E                                       211,896        73.711255      15,619.12
                            NELSON 3/TENN M                                      1,700,865        72.146243     122,711.02
                            NELSON 3/TETCO E                                       310,513        74.583769      23,159.23
                            NELSON 3/TETCO M                                     4,149,185        72.377696     300,308.45
                            NELSON 4/FLORIDA E                                   7,000,169        61.712570     431,998.42
                            NELSON 4/TARGA E                                    14,524,924        61.566255     894,245.17
                            NELSON 4/TENN E                                     12,398,148        61.183407     758,560.93
                            NELSON 4/TENN M                                     11,564,685        62.458012     722,307.24
                            NELSON 4/TETCO E                                       673,803        62.029837      41,795.89
                            NELSON 4/TETCO I                                     4,071,417        60.797956     247,533.83
                            NELSON 4/TETCO M                                    20,958,943        62.744334   1,315,054.91
                            NRG POWER MARKETING LLC./WSPP A                        287,250        84.000000      24,129.00
                            NRG POWER MARKETING LLC./WSPP B                      3,866,468        63.031477     243,709.19
                            NRG POWER MARKETING LLC./WSPP C                        576,051        61.175903      35,240.44
                            OCCIDENTAL POWER SERVICES/WSPP B                       860,110        64.057109      55,096.16
                            RAINBOW ENERGY MARKETING CORP/WSPP A                    16,988        45.500353         772.96
                            SABINE 1/CENTANA#3 E                                   528,309        58.315891      30,808.81
                            SABINE 1/CENTANA#3 M                                11,158,610        60.270426     672,534.18
                            SABINE 1/ENBRIDGE E                                  2,981,642        59.069701     176,124.70
                            SABINE 1/ENBRIDGE M                                 13,526,870        59.643680     806,792.30
                            SABINE 1/HPL/CH E                                      988,225        59.296527      58,598.31
                            SABINE 1/STORAGE I                                   1,426,945        55.129616      78,666.93
                            SABINE 1/TEJAS E                                       121,659        59.397414       7,226.23
                            SABINE 1/TEJAS M                                       947,156        60.289340      57,103.41
                            SABINE 2/CENTANA#3 E                                    91,908        56.319798       5,176.24
                            SABINE 2/CENTANA#3 M                                   664,972        56.811565      37,778.10
                            SABINE 2/ENBRIDGE E                                    692,152        55.256562      38,245.94
                            SABINE 2/ENBRIDGE M                                  7,036,036        56.249057     395,770.39
                            SABINE 2/STORAGE I                                      44,850        51.999108       2,332.16
                            SABINE 2/TEJAS M                                       908,661        56.809272      51,620.37
                            SABINE 3/CENTANA#3 E                                 1,060,597        59.090201      62,670.89
                            SABINE 3/CENTANA#3 M                                16,217,549        58.704064     952,036.04
                            SABINE 3/ENBRIDGE E                                  3,103,193        58.061200     180,175.11
                            SABINE 3/ENBRIDGE M                                 12,241,869        58.110576     711,382.06
                            SABINE 3/HPL/CH E                                      326,498        58.477785      19,092.88
                            SABINE 3/STORAGE I                                      10,324        53.748547         554.90
                            SABINE 3/TEJAS E                                       925,496        59.023659      54,626.16
                            SABINE 3/TEJAS M                                     7,186,222        58.774696     422,368.01
                            SABINE 4/CENTANA#3 M                                   453,221        54.745257      24,811.70
                            SABINE 4/ENBRIDGE E                                  2,601,263        53.583790     139,385.53
                            SABINE 4/ENBRIDGE M                                  2,257,273        54.260118     122,479.90
 Attachment Snapshot: 20100826181933                             RunID: 17029                                          Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                            9-187
                                                                                                                        Exhibit PJC-2
                                                                                                                   2011 TX Rate Case
                                                                                                                        Page 26 of 70




 Entergy Electric System                           Date range - 20100701 through 20100731                                               Attachment 2
 Intra-System Billing-201007RA           Energy Sold to Exchange - Entergy Gulf States Louisiana, LLC                                        Page 26

                                             Source                               KWH           Mills per KWH     Cost

                            SABINE 4/HPL/CH E                                         123,231        53.774943        6,626.74
                            SABINE 4/STORAGE I                                        354,533        52.808342       18,722.30
                            SABINE 4/TEJAS M                                          540,521        54.799166       29,620.10
                            SABINE 5/CENTANA#3 M                                   12,993,537        60.726777      789,055.62
                            SABINE 5/ENBRIDGE E                                     3,605,523        60.124634      216,780.75
                            SABINE 5/ENBRIDGE M                                     3,707,371        60.131940      222,931.41
                            SABINE 5/HPL/CH E                                       2,059,458        61.208420      126,056.17
                            SABINE 5/TEJAS E                                        1,643,812        61.391668      100,916.36
                            SABINE 5/TEJAS M                                       38,907,022        60.796120    2,365,395.96
                            SMEPA/WSPP B                                              569,717        89.186491       50,811.06
                            SOUTHERN COMPANY SERVICES INC. AS                       1,771,646       128.000001      226,770.69
                            SUEZ Energy Marketing NA Inc./WSPP B                       87,489        53.713153        4,699.31
                            TENASKA/WSPP A                                            253,868        62.640624       15,902.45
                            TENASKA/WSPP B                                          2,782,607        64.098886      178,362.01
                            UNION POWER PARTNERS/WSPP B                               993,273        55.584890       55,210.97
                            WESTAR ENERGY INC/WSPP B                                   97,958        56.092203        5,494.68
                            WESTAR ENERGY INC/WSPP C                                  153,200        62.000000        9,498.40
                            WILLOW GLEN 1/BL HOLDINGS E                             7,061,062        62.406062      440,653.07
                            WILLOW GLEN 2/BL HOLDINGS E                            13,042,792        71.414827      931,448.74
                            WILLOW GLEN 4/BL HOLDINGS E                            68,607,715        59.777690    4,101,210.69

                            Totals                                                388,628,993        60.953251   23,688,200.69




 Attachment Snapshot: 20100826181933                               RunID: 17029                                            Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                                9-188
                                                                                                                    Exhibit PJC-2
                                                                                                               2011 TX Rate Case
                                                                                                                    Page 27 of 70




 Entergy Electric System                          Date range - 20100701 through 20100731                                            Attachment 2
 Intra-System Billing-201007RA                  Energy Sold to Exchange - Entergy Texas, Inc                                             Page 27

                                            Source                               KWH          Mills per KWH    Cost

                            AECI/WSPP C SYSTEM FIRM                                 43,518         62.999908     2,741.63
                            DOW P PELINE COMPANY/INTRA-DAY CALL                    274,685         63.636784    17,480.07
                            JBO/WSPP A                                              75,631         70.000000     5,294.17
                            JBO/WSPP B                                             111,406         73.000018     8,132.64
                            NELSON 4/FLORIDA E                                      47,337         62.611065     2,963.82
                            NELSON 4/TARGA E                                       121,380         62.737354     7,615.06
                            NELSON 4/TENN E                                         17,782         62.358002     1,108.85
                            NELSON 4/TENN M                                         57,443         62.438939     3,586.68
                            NELSON 4/TETCO M                                       177,010         62.728942    11,103.65
                            NRG POWER MARKETING LLC./WSPP A                        225,360         84.000000    18,930.24
                            OCCIDENTAL POWER SERVICES/WSPP B                        32,720         66.000000     2,159.52
                            SMEPA/WSPP B                                           167,697         98.509812    16,519.80
                            SOUTHERN COMPANY SERVICES INC. AS                      322,527        128.000012    41,283.46
                            TENASKA/WSPP A                                          15,456         63.049948       974.50
                            WILLOW GLEN 2/BL HOLDINGS E                            569,266         72.351045    41,186.99

                            Totals                                                2,259,218        80.152106   181,081.08




 Attachment Snapshot: 20100826181933                              RunID: 17029                                         Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                             9-189
                                                                                                                           Exhibit PJC-2
                                                                                                                      2011 TX Rate Case
                                                                                                                           Page 28 of 70




 Entergy Electric System                                Date range - 20100701 through 20100731                                             Attachment 2
 Intra-System Billing-201007RA                                 Energy Sold to Exchange                                                          Page 28

                                           Company                                   KWH           Mills per KWH          Cost

                   Entergy Arkansas, Inc.                                            131,743,223          39.967947       5,265,506.15
                   Entergy Louisiana, LLC                                            135,105,357          75.690241      10,226,157.06
                   Entergy Mississippi, Inc.                                          32,027,550          63.895088       2,046,403.14
                   Entergy New Orleans, Inc.                                          31,587,544          61.929948       1,956,214.96
                   Entergy Gulf States Louisiana, LLC                                388,628,993          60.953251      23,688,200.69
                   Entergy Texas, Inc                                                  2,259,218          80.152106         181,081.08

                   Totals                                                            721,351,885          60.114299      43,363,563.08




 Attachment Snapshot: 20100826181933                                  RunID: 17029                                            Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                                    9-190
                                                                                                                           Exhibit PJC-2
                                                                                                                      2011 TX Rate Case
                                                                                                                           Page 29 of 70




 Entergy Electric System                                Date range - 20100701 through 20100731                                             Attachment 2
 Intra-System Billing-201007RA                             Energy Purchased from Exchange                                                       Page 29

                                           Company                                   KWH           Mills per KWH          Cost

                   Entergy Arkansas, Inc.                                            131,563,443          64.953756       8,545,539.76
                   Entergy Louisiana, LLC                                             42,272,082          50.486528       2,134,170.65
                   Entergy Mississippi, Inc.                                         165,417,337          64.005776      10,587,664.98
                   Entergy New Orleans, Inc.                                          45,025,369          58.268323       2,623,552.75
                   Entergy Gulf States Louisiana, LLC                                  8,681,301          37.886068         328,900.36
                   Entergy Texas, Inc                                                328,392,353          58.295312      19,143,734.58

                   Totals                                                            721,351,885          60.114299      43,363,563.08




 Attachment Snapshot: 20100826181933                                  RunID: 17029                                            Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                                    9-191
                                                                                                                           Exhibit PJC-2
                                                                                                                      2011 TX Rate Case
                                                                                                                           Page 30 of 70




 Entergy Electric System                                 Date range - 20100701 through 20100731                                             Attachment 2
 Intra-System Billing-201007RA                                 Unit Power Purchases - KWH                                                        Page 30

                                       Generating Unit          AR         LA         MS          NO        EGSL         ETI

                            ACADIA POWER PARTNERS,                   0           0         0            0 59,708,320            0
                            ARK.NU 1 - UPP from AR                   0 24,991,859 11,975,579   16,947,775 15,851,160 16,654,966
                            ARK.NU 2 - UPP from AR                   0 29,534,318 14,206,469   19,989,454 18,809,417 19,768,134
                            CALCAS EU 1 - UPP from EGSL              0           0         0            0           0   4,690,725
                            CALCAS EU 2 - UPP from EGSL              0           0         0            0           0   5,250,450
                            GGULF RET - UPP from AR                  0 19,691,908  8,775,642   13,799,542 11,616,357 12,205,279
                            GGULF RP - UPP from AR                   0   9,494,456 4,440,083    6,514,363   5,876,574   6,173,783
                            INDEPN 1 - UPP from AR                   0   7,145,175 3,421,107    4,846,579   4,526,010   4,757,472
                            LEWIS CREEK 1 - UPP from ETI             0           0         0            0 58,217,025            0
                            LEWIS CREEK 2 - UPP from ETI             0           0         0            0 65,725,375            0
                            NELSON 3 - UPP from EGSL                 0           0         0            0           0   5,192,225
                            NELSON 4 - UPP from EGSL                 0           0         0            0           0 62,280,775
                            PERV L 1 - UPP from EGSL                 0           0         0            0           0 82,838,753
                            PERV L 1 - UPP from LA                   0           0         0            0 194,914,500           0
                            RVRBND 1 - UPP from EGSL                 0 139,555,800         0   69,777,900           0 207,589,429
                            SABINE 1 - UPP from ETI                  0           0         0            0 51,146,250            0
                            SABINE 2 - UPP from ETI                  0           0         0            0 50,562,050            0
                            SABINE 3 - UPP from ETI                  0           0         0            0 80,097,500            0
                            SABINE 4 - UPP from ETI                  0           0         0            0 76,167,950            0
                            SABINE 5 - UPP from ETI                  0           0         0            0 70,933,725            0
                            WH.BLF 1 - UPP from AR                   0 13,440,805  6,292,389    8,494,462   8,331,086   8,755,797
                            WH.BLF 2 - UPP from AR                   0 10,706,289  5,295,338    7,753,353   7,011,078   7,368,498
                            WILLOW GLEN 1 - UPP from                 0           0         0            0           0   5,445,950
                            WILLOW GLEN 2 - UPP from                 0           0         0            0           0 10,391,250
                            WILLOW GLEN 4 - UPP from                 0           0         0            0           0 77,447,750

                            Totals                                   0 254,560,610 54,406,607 148,123,428 779,494,377 536,811,236




 Attachment Snapshot: 20100826181933                                   RunID: 17029                                            Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                                   9-192
                                                                                                                           Exhibit PJC-2
                                                                                                                      2011 TX Rate Case
                                                                                                                           Page 31 of 70




 Entergy Electric System                                Date range - 20100701 through 20100731                                             Attachment 2
 Intra-System Billing-201007RA                                   AECC Excess Energy                                                             Page 31

                                           Company                                   KWH           Mills per KWH          Cost

                   Entergy Arkansas, Inc.                                             12,108,854          32.952174           399,013.07
                   Entergy Louisiana, LLC                                             14,584,886          32.951794           480,598.16
                   Entergy Mississippi, Inc.                                           8,083,973          32.951544           266,379.39
                   Entergy New Orleans, Inc.                                           2,621,176          32.951442            86,371.53
                   Entergy Gulf States Louisiana, LLC                                 11,105,658          32.952414           365,958.24
                   Entergy Texas, Inc                                                  9,487,663          32.952434           312,641.59

                   Totals                                                             57,992,210          32.952046       1,910,961.98




 Attachment Snapshot: 20100826181933                                  RunID: 17029                                            Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                                    9-193
                                                                                                                       Exhibit PJC-2
                                                                                                                  2011 TX Rate Case
                                                                                                                       Page 32 of 70




 Entergy Electric System                            Date range - 20100701 through 20100731                                             Attachment 3
 Intra-System Billing-201007RA                              Joint Account Deliveries                                                        Page 32

                                       Company / Type                            KWH           Mills per KWH         Charge

                   AECC/1-NON F RM                                                    60,000          53.000000             3,180.00
                   AECI/WSPP A                                                       750,000          41.773333            31,330.00
                   AEP SERVICE CORP./SPP ASSIST                                      135,000          65.750074             8,876.26
                   AEP SERVICE CORP./WSPP A                                          850,000          30.352941            25,800.00
                   BNP PAR BAS ENERGY TRADING GP/WSPP A                              150,000          68.000000            10,200.00
                   BOARD OF PUBLIC UTILITIES/SPP ASSIST                               15,000          66.000000               990.00
                   CITIGROUP ENERGY NC/WSPP A                                        208,000          57.442308            11,948.00
                   CLECO/SPP ASSIST                                                  260,000          68.860923            17,903.84
                   CONSTELLATION ENERGY COMM/SPP ASSIST                                5,000          77.000000               385.00
                   CONSTELLATION ENERGY COMMOD/SPP ASSIST (W                          15,000          64.162000               962.43
                   CONSTELLATION ENERGY COMMODIT /SPP ASSIST                          71,000          75.745070             5,377.90
                   CONSTELLATION ENERGY COMMODIT E/SWPP ASSIST                        15,000          61.259333               918.89
                   CONSTELLATION ENERGY COMMODIT ES GR/WSPP C                        300,000          59.270000            17,781.00
                   CONSTELLATION ENERGY COMMODIT ES GROUP /1-                         24,000          51.625000             1,239.00
                   CONSTELLATION ENERGY COMMODIT ES/SPP ASSIST                         8,000          72.875000               583.00
                   COTTONWOOD ENERGY CO/DEF110                                       642,523          74.096678            47,608.82
                   CYPRES/DEF110                                                     528,066          80.697167            42,613.43
                   DUKE ENERGY H NDS/DEF110                                          190,414          62.675066            11,934.21
                   DUKEENERGY HOTSPR NG/DEF110                                       214,680          71.472098            15,343.63
                   GRDA/SPP ASSIST                                                    79,000          58.944937             4,656.65
                   KANSAS CITY POWER & LIGHT COMPANY/SPP ASSIST                      488,000          70.980246            34,638.36
                   KANSAS CITY POWER & LIGHT COMPANY/WSPP A                          100,000          63.000000             6,300.00
                   MAGNET COVE/DEF110                                                648,504          67.715326            43,913.66
                   MDEA CROSSROADS/DEF110                                             63,959          78.770306             5,038.07
                   MISSOURI PUBLIC SERVICE/SPP ASSIST                                489,000          69.808732            34,136.47
                   NPPD/SPP ASSIST                                                   177,000          55.965480             9,905.89
                   NRG POWER MARKETING LLC./1-NON FIRM                               275,000          42.000000            11,550.00
                   NRG POWER MARKETING LLC./SPP ASSIST                               149,000          74.895973            11,159.50
                   NRG POWER MARKETING LLC./WSPP C DAMAGES                         1,200,000          65.258125            78,309.75
                   OCCIDENTAL CHEM CORP/DEF110                                        17,810          69.602471             1,239.62
                   OG&E/SPP ASSIST                                                   306,000          77.899608            23,837.28
                   PPG INDUSTRIES/DEF110                                              28,405          80.299947             2,280.92
                   RS COGEN LLC/DEF110                                                   108          81.388889                 8.79
                   SPS/SPP ASSIST                                                     58,000          55.541379             3,221.40
                   SRW COGENERATION/DEF110                                            54,784          79.191917             4,338.45
                   SUNFLOWER/SPP ASSIST                                                6,000          69.300000               415.80
                   SUNFLOWER/SWPP ASSIST                                             124,000          58.196129             7,216.32
                   SWPA/SPP ASSIST                                                    85,000          65.334000             5,553.39
                   TENASKA FRONTIER/DEF110                                           328,937          68.567780            22,554.48
                   TENASKA/WSPP A                                                     50,000          36.000000             1,800.00
                   WESTAR ENERGY NC/SPP ASSIST                                        93,000          69.512903             6,464.70
                   WESTAR ENERGY NC/WSPP A                                           150,000          35.000000             5,250.00
                   WESTAR ENERGY NC/WSPP C DAMAGES                                   412,000          70.000000            28,840.00
                   WESTERN FARMERS/SPP ASSIST                                         15,000          68.200000             1,023.00
                   WRIGHTSVILE POWER/DEF110                                          315,742          78.991582            24,940.96
                   YAZOO CITY/DEF110                                                  16,104          91.066816             1,466.54

                   Totals                                                         10,172,036          62.429528           635,035.41




 Attachment Snapshot: 20100826181933                              RunID: 17029                                            Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                                9-194
                                                                                                                     Exhibit PJC-2
                                                                                                                2011 TX Rate Case
                                                                                                                     Page 33 of 70




 Entergy Electric System                           Date range - 20100701 through 20100731                                            Attachment 3
 Intra-System Billing-201007RA             Joint Account Delivery Sources - Entergy Arkansas, Inc.                                        Page 33

                                       Source                          KWH                  Mills per KWH         Charge

                   AECI/WSPP C SYSTEM FIRM                                         3,288            62.858881               206.68
                   AMEREN ENERGY NC. (AE) ACTING /WSPP C                           2,040            61.000000               124.44
                   CALPINE ENERGY SERVICES L.P./WSPP B                            15,413            54.792059               844.51
                   CLECO/WSPP B                                                   83,404            63.829672             5,323.65
                   CONSTELLATION ENERGY COMMODIT ES                                  685            45.328467                31.05
                   DB ENERGY TRADING LLC/WSPP B                                  111,632            54.443529             6,077.64
                   ENDURE ENERGY/WSPP A                                            1,200            52.000000                62.40
                   EXELON GENERATION COMPANY LLC/DAILY                            30,776            40.569925             1,248.58
                   J ARON & COMPANY/WSPP B                                        11,882            56.502272               671.36
                   J.P. MORGAN VENTURES ENERGY                                   116,233            68.000052             7,903.85
                   JBO/WSPP A                                                    264,226            70.911228            18,736.59
                   JBO/WSPP B                                                     52,181            70.734367             3,690.99
                   L.CATH 4/CEGT E                                                   710            45.464789                32.28
                   MERR LL LYNCH COMMODITIES INC/WSPP B                          231,161            50.663737            11,711.48
                   NRG POWER MARKETING LLC./WSPP B                               386,954            60.796374            23,525.40
                   NRG POWER MARKETING LLC./WSPP C                                 6,241            65.000801               405.67
                   OCCIDENTAL POWER SERVICES/WSPP B                               65,502            66.050808             4,326.46
                   SMEPA/WSPP B                                                    5,211            98.508923               513.33
                   SOUTHERN COMPANY SERVICES INC. AS                             281,583           128 000021            36,042.63
                   SUEZ Energy Marketing NA Inc./WSPP B                           63,182            51.789275             3,272.15
                   TENASKA/WSPP A                                                  6,331            60.830832               385.12
                   TENASKA/WSPP B                                                 30,929            63.290439             1,957.51
                   UNION POWER PARTNERS/WSPP B                                   140,230            52.566783             7,371.44
                   WESTAR ENERGY NC/WSPP B                                         2,312            49.247405               113.86

                   Totals                                                       1,913,306           70.338498           134,579.07




 Attachment Snapshot: 20100826181933                             RunID: 17029                                           Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                              9-195
                                                                                                                     Exhibit PJC-2
                                                                                                                2011 TX Rate Case
                                                                                                                     Page 34 of 70




 Entergy Electric System                           Date range - 20100701 through 20100731                                            Attachment 3
 Intra-System Billing-201007RA             Joint Account Delivery Sources - Entergy Louisiana, LLC                                        Page 34

                                       Source                          KWH                  Mills per KWH         Charge

                   ACADIA POWER PARTNERS, LLC/WSPP B                              65,625            39.956419             2,622.14
                   AECI/WSPP C SYSTEM FIRM                                         3,960            62.858586               248.92
                   AMEREN ENERGY NC. (AE) ACTING /WSPP C                           2,458            61.000814               149.94
                   BURAS TEMP                                                     86,670           260 515403            22,578.87
                   CALPINE ENERGY SERVICES L.P./WSPP B                            18,572            54.790545             1,017.57
                   CLECO/WSPP B                                                  100,472            63.829326             6,413.06
                   CONSTELLATION ENERGY COMMODIT ES                                  826            45.326877                37.44
                   DB ENERGY TRADING LLC/WSPP B                                  134,470            54.443816             7,321.06
                   ENDURE ENERGY/WSPP A                                            1,445            52.000000                75.14
                   EXELON GENERATION COMPANY LLC/DAILY                            37,078            40.569610             1,504.24
                   J ARON & COMPANY/WSPP B                                        14,314            56.502725               808.78
                   J.P. MORGAN VENTURES ENERGY                                   140,006            67.999871             9,520.39
                   JBO/WSPP A                                                    318,288            70.911376            22,570.24
                   JBO/WSPP B                                                     62,870            70.734054             4,447.05
                   L.GPSY 3/BRDGLN E                                                 837            47.849462                40.05
                   MERR LL LYNCH COMMODITIES INC/WSPP B                          278,442            50.664124            14,107.02
                   NINEMI 4/EVANG(LT) M                                              603            47.877280                28.87
                   NINEMI 5/BRDGLN E                                              48,816            46.392371             2,264.69
                   NRG POWER MARKETING LLC./WSPP B                               466,111            60.796184            28,337.77
                   NRG POWER MARKETING LLC./WSPP C                                 7,518            65.001330               488.68
                   OCCIDENTAL POWER SERVICES/BASE                                221,973            35.759034             7,937.54
                   OCCIDENTAL POWER SERVICES/DAY-AHEAD                             5,441            41.705569               226.92
                   OCCIDENTAL POWER SERVICES/INTRA-DAY                            40,869            52.705474             2,154.02
                   OCCIDENTAL POWER SERVICES/WSPP B                               78,904            66.050771             5,211.67
                   SMEPA/WSPP B                                                    6,277            98.510435               618.35
                   SOUTHERN COMPANY SERVICES INC. AS                             339,169           128 000024            43,413.64
                   SUEZ Energy Marketing NA Inc./WSPP B                           76,107            51.789717             3,941.56
                   TENASKA/WSPP A                                                  7,625            60.828852               463.82
                   TENASKA/WSPP B                                                 37,261            63.290572             2,358.27
                   UNION POWER PARTNERS/WSPP B                                   168,919            52.566733             8,879.52
                   WESTAR ENERGY NC/WSPP B                                         2,786            49.249821               137.21

                   Totals                                                       2,774,712           72.052321           199,924.44




 Attachment Snapshot: 20100826181933                             RunID: 17029                                           Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                              9-196
                                                                                                                       Exhibit PJC-2
                                                                                                                  2011 TX Rate Case
                                                                                                                       Page 35 of 70




 Entergy Electric System                           Date range - 20100701 through 20100731                                              Attachment 3
 Intra-System Billing-201007RA             Joint Account Delivery Sources - Entergy Mississippi, Inc.                                       Page 35

                                       Source                            KWH                  Mills per KWH         Charge

                   AECI/WSPP C SYSTEM FIRM                                           2,194            62.857794               137.91
                   AMEREN ENERGY NC. (AE) ACTING /WSPP C                             1,361            61.006613                83.03
                   ANDRUS 1/TENN E                                                  27,261            43.250064             1,179.04
                   ANDRUS 1/TENN I                                                     345            46.550725                16.06
                   B.WLSN 1/COLUMBIA ML E                                            1,382            46.714906                64.56
                   B.WLSN 2/COLUMBIA ML E                                            8,426            46.840731               394.68
                   CALPINE ENERGY SERVICES L.P./WSPP B                              10,293            54.793549               563.99
                   CLECO/WSPP B                                                     55,684            63.829825             3,554.30
                   CONSTELLATION ENERGY COMMODIT ES                                    458            45.327511                20.76
                   DB ENERGY TRADING LLC/WSPP B                                     74,525            54.443744             4,057.42
                   ENDURE ENERGY/WSPP A                                                801            51.997503                41.65
                   EXELON GENERATION COMPANY LLC/DAILY                              20,546            40.570427               833.56
                   J ARON & COMPANY/WSPP B                                           7,931            56.498550               448.09
                   J.P. MORGAN VENTURES ENERGY                                      77,599            67.999974             5,276.73
                   JBO/WSPP A                                                      176,406            70.911307            12,509.18
                   JBO/WSPP B                                                       34,835            70.733458             2,464.00
                   MEAM CANTON 1       N                                             8,863           120 910527             1,071.63
                   MEAM CANTON 2       N                                             8,000           120 910000               967.28
                   MEAM CANTON 3       N                                             8,000           120 910000               967.28
                   MEAM CANTON 4       N                                             8,011           120 909999               968.61
                   MEAM CANTON 5       N                                            10,000           120 910000             1,209.10
                   MEAM HENDERSON 10 IN                                              5,000           120 910000               604.55
                   MEAM HENDERSON 11 IN                                              8,000           120 910000               967.28
                   MEAM HENDERSON 2 IN                                              68,916           120 907627             8,332.47
                   MEAM HENDERSON 4 IN                                              13,858           120 909944             1,675.57
                   MEAM HENDERSON 5 IN                                              14,166           120 909925             1,712.81
                   MEAM HENDERSON 6 IN                                              15,000           120 910000             1,813.65
                   MEAM HENDERSON 7 IN                                              19,159           120 910277             2,316.52
                   MEAM HENDERSON 8 IN                                              24,750           120 909899             2,992.52
                   MEAM HENDERSON 9 IN                                              23,222           120 910344             2,807.78
                   MERR LL LYNCH COMMODITIES INC/WSPP B                            154,326            50.663660             7,818.72
                   NRG POWER MARKETING LLC./WSPP B                                 258,334            60.796604            15,705.83
                   NRG POWER MARKETING LLC./WSPP C                                   4,167            65.003600               270.87
                   OCCIDENTAL POWER SERVICES/WSPP B                                 43,731            66.052228             2,888.53
                   SMEPA/WSPP B                                                      3,479            98.511066               342.72
                   SOUTHERN COMPANY SERVICES INC. AS                               187,994           128 000043            24,063.24
                   SUEZ Energy Marketing NA Inc./WSPP B                             42,184            51.789304             2,184.68
                   TENASKA/WSPP A                                                    4,226            60.828206               257.06
                   TENASKA/WSPP B                                                   20,648            63.290391             1,306.82
                   UNION POWER PARTNERS/WSPP B                                      93,622            52.566811             4,921.41
                   WESTAR ENERGY NC/WSPP B                                           1,543            49.254699                76.00

                   Totals                                                         1,549,246           77.384670           119,887.89




 Attachment Snapshot: 20100826181933                               RunID: 17029                                           Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                                9-197
                                                                                                                    Exhibit PJC-2
                                                                                                               2011 TX Rate Case
                                                                                                                    Page 36 of 70




 Entergy Electric System                           Date range - 20100701 through 20100731                                           Attachment 3
 Intra-System Billing-201007RA            Joint Account Delivery Sources - Entergy New Orleans, Inc.                                     Page 36

                                       Source                           KWH                Mills per KWH         Charge

                   AECI/WSPP C SYSTEM FIRM                                           712           62.837079                44.74
                   AMEREN ENERGY NC. (AE) ACTING /WSPP C                             441           61.020408                26.91
                   CALPINE ENERGY SERVICES L.P./WSPP B                             3,336           54.805156               182.83
                   CLECO/WSPP B                                                   18,049           63.829575             1,152.06
                   CONSTELLATION ENERGY COMMODIT ES                                  148           45.337838                 6.71
                   DB ENERGY TRADING LLC/WSPP B                                   24,166           54.441364             1,315.63
                   ENDURE ENERGY/WSPP A                                              260           52.000000                13.52
                   EXELON GENERATION COMPANY LLC/DAILY                             6,665           40.565641               270.37
                   J ARON & COMPANY/WSPP B                                         2,571           56.503306               145.27
                   J.P. MORGAN VENTURES ENERGY                                    25,160           68.000000             1,710.88
                   JBO/WSPP A                                                     57,191           70.911157             4,055.48
                   JBO/WSPP B                                                     11,297           70.733823               799.08
                   MERR LL LYNCH COMMODITIES INC/WSPP B                           50,042           50.664842             2,535.37
                   MICHOD 2/BRDGLN E                                               5,370           40.242086               216.10
                   MICHOD 2/GSPL E                                                12,219           44.370243               542.16
                   NRG POWER MARKETING LLC./WSPP B                                83,767           60.795898             5,092.69
                   NRG POWER MARKETING LLC./WSPP C                                 1,351           65.011103                87.83
                   OCCIDENTAL POWER SERVICES/WSPP B                               14,178           66.055156               936.53
                   SMEPA/WSPP B                                                    1,128           98.510638               111.12
                   SOUTHERN COMPANY SERVICES INC. AS                              60,954          128 000295             7,802.13
                   SUEZ Energy Marketing NA Inc./WSPP B                           13,678           51.788273               708.36
                   TENASKA/WSPP A                                                  1,370           60.832117                83.34
                   TENASKA/WSPP B                                                  6,694           63.288019               423.65
                   UNION POWER PARTNERS/WSPP B                                    30,359           52.566949             1,595.88
                   WESTAR ENERGY NC/WSPP B                                           500           49.260000                24.63

                   Totals                                                        431,606           69.237383           29,883.27




 Attachment Snapshot: 20100826181933                              RunID: 17029                                         Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                             9-198
                                                                                                                Exhibit PJC-2
                                                                                                           2011 TX Rate Case
                                                                                                                Page 37 of 70




 Entergy Electric System                    Date range - 20100701 through 20100731                                              Attachment 3
 Intra-System Billing-201007RA Joint Account Delivery Sources - Entergy Gulf States Louisiana, LLC                                   Page 37

                                       Source                     KWH                  Mills per KWH         Charge

                   ACADIA POWER PARTNERS, LLC/WSPP B                         32,812            39.956114             1,311.04
                   AECI/WSPP C SYSTEM FIRM                                    3,015            62.855721               189.51
                   AMEREN ENERGY NC. (AE) ACTING /WSPP C                      1,871            60.999466               114.13
                   CALPINE ENERGY SERVICES L.P./WSPP B                       14,137            54.792389               774.60
                   CLECO/WSPP B                                              76,488            63.829620             4,882.20
                   CONSTELLATION ENERGY COMMODIT ES                             628            45.318471                28.46
                   DB ENERGY TRADING LLC/WSPP B                             102,387            54.443728             5,574.33
                   DOW PIPELINE COMPANY/INTRA-DAY CALL                       10,862            63.936660               694.48
                   ENDURE ENERGY/WSPP A                                       1,100            52.000000                57.20
                   EXELON GENERATION COMPANY LLC/DAILY                       28,226            40.569333             1,145.11
                   J ARON & COMPANY/WSPP B                                   10,896            56.502386               615.65
                   J.P. MORGAN VENTURES ENERGY                              106,603            67.999869             7,248.99
                   JBO/WSPP A                                               242,333            70.911391            17,184.17
                   JBO/WSPP B                                                47,860            70.733180             3,385.29
                   LEWIS CREEK 1/COPANO M                                    15,337            44.627372               684.45
                   LEWIS CREEK 1/TETCO E                                      6,900            43.344928               299.08
                   LEWIS CREEK 1/TETCO M                                      1,878            42.923323                80.61
                   LEWIS CREEK 2/COPANO E                                        10            43.000000                 0.43
                   LEWIS CREEK 2/COPANO M                                       519            43.757225                22.71
                   LEWIS CREEK 2/TETCO E                                     12,307            45.314049               557.68
                   LEWIS CREEK 2/TETCO I                                      1,239            42.695722                52.90
                   LEWIS CREEK 2/TETCO M                                     13,767            43.846154               603.63
                   MERR LL LYNCH COMMODITIES INC/WSPP B                     212,012            50.663972            10,741.37
                   NELSON 4/TENN M                                              836            43.277512                36.18
                   NELSON 4/TETCO I                                               1            40.000000                 0.04
                   NELSON 4/TETCO M                                          19,976            44.455346               888.04
                   NRG POWER MARKETING LLC./WSPP B                          354,890            60.796219            21,575.97
                   NRG POWER MARKETING LLC./WSPP C                            5,725            65.002620               372.14
                   OCCIDENTAL POWER SERVICES/WSPP B                          60,074            66.051370             3,967.97
                   SAB NE 1/CENTANA#3 M                                         575            44.921739                25.83
                   SAB NE 1/ENBRIDGE E                                            6            46.666667                 0.28
                   SAB NE 1/ENBRIDGE M                                       13,745            45.014187               618.72
                   SAB NE 2/ENBRIDGE E                                       14,950            44.728428               668.69
                   SAB NE 2/ENBRIDGE M                                        1,398            46.108727                64.46
                   SAB NE 2/STORAGE I                                           575            46.852174                26.94
                   SAB NE 3/CENTANA#3 M                                       4,026            46.395926               186.79
                   SAB NE 3/ENBRIDGE E                                          179            46.145251                 8.26
                   SAB NE 3/ENBRIDGE M                                           71            47.464789                 3.37
                   SAB NE 3/TEJAS M                                             575            46.121739                26.52
                   SAB NE 4/ENBRIDGE E                                          575            44.886957                25.81
                   SAB NE 5/CENTANA#3 M                                          12            48.333333                 0.58
                   SMEPA/WSPP B                                               4,779            98.510149               470.78
                   SOUTHERN COMPANY SERVICES INC. AS                        258,254           127.999992            33,056.51
                   SUEZ Energy Marketing NA Inc./WSPP B                      57,947            51.789739             3,001.06
                   TENASKA/WSPP A                                             5,805            60.830319               353.12
                   TENASKA/WSPP B                                            28,365            63.289970             1,795.22
                   UNION POWER PARTNERS/WSPP B                              128,615            52.566886             6,760.89
                   WESTAR ENERGY NC/WSPP B                                    2,120            49.245283               104.40
                   WILLOW GLEN 2/BL HOLDINGS E                                2,589            44.998069               116.50
                   WILLOW GLEN 4/BL HOLDINGS E                                2,358            45.979644               108.42

                   Totals                                                  1,912,208           68.251733           130,511.51




 Attachment Snapshot: 20100826181933                        RunID: 17029                                           Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                         9-199
                                                                                                                        Exhibit PJC-2
                                                                                                                   2011 TX Rate Case
                                                                                                                        Page 38 of 70




 Entergy Electric System                              Date range - 20100701 through 20100731                                            Attachment 3
 Intra-System Billing-201007RA                  Joint Account Delivery Sources - Entergy Texas, Inc                                          Page 38

                                       Source                             KWH                  Mills per KWH         Charge

                   AECI/WSPP C SYSTEM FIRM                                            2,575            62.854369               161.85
                   AMEREN ENERGY NC. (AE) ACTING /WSPP C                              1,597            60.989355                97.40
                   CALPINE ENERGY SERVICES L.P./WSPP B                               12,072            54.773857               661.23
                   CLECO/WSPP B                                                      65,339            63.829413             4,170.55
                   CONSTELLATION ENERGY COMMODIT ES                                     537            45.307263                24.33
                   DB ENERGY TRADING LLC/WSPP B                                      87,457            54.444241             4,761.53
                   DOW PIPELINE COMPANY/INTRA-DAY CALL                                8,028            63.937469               513.29
                   ENDURE ENERGY/WSPP A                                                 939            52.002130                48.83
                   EXELON GENERATION COMPANY LLC/DAILY                               24,106            40.568738               977.95
                   J ARON & COMPANY/WSPP B                                            9,303            56.492529               525.55
                   J.P. MORGAN VENTURES ENERGY                                       91,065            68.000000             6,192.42
                   JBO/WSPP A                                                       206,999            70.911116            14,678.53
                   JBO/WSPP B                                                        40,878            70.731689             2,891.37
                   LEWIS CREEK 1/COPANO M                                            11,337            44.627326               505.94
                   LEWIS CREEK 1/TETCO E                                              5,100            43.345098               221.06
                   LEWIS CREEK 1/TETCO M                                              1,387            42.927181                59.54
                   LEWIS CREEK 2/COPANO E                                                 8            42.500000                 0.34
                   LEWIS CREEK 2/COPANO M                                               385            43.740260                16.84
                   LEWIS CREEK 2/TETCO E                                              9,096            45.313325               412.17
                   LEWIS CREEK 2/TETCO I                                                916            42.696507                39.11
                   LEWIS CREEK 2/TETCO M                                             10,177            43.846910               446.23
                   MERR LL LYNCH COMMODITIES INC/WSPP B                             181,101            50.663884             9,175.28
                   NELSON 4/TENN M                                                      618            43.284790                26.75
                   NELSON 4/TETCO I                                                       1            40.000000                 0.04
                   NELSON 4/TETCO M                                                  14,765            44.453099               656.35
                   NRG POWER MARKETING LLC./WSPP B                                  303,142            60.796096            18,429.85
                   NRG POWER MARKETING LLC./WSPP C                                    4,888            64.989771               317.67
                   OCCIDENTAL POWER SERVICES/WSPP B                                  51,305            66.044440             3,388.41
                   SAB NE 1/CENTANA#3 M                                                 425            44.941176                19.10
                   SAB NE 1/ENBRIDGE E                                                    5            48.000000                 0.24
                   SAB NE 1/ENBRIDGE M                                               10,159            45.018210               457.34
                   SAB NE 2/ENBRIDGE E                                               11,050            44.729412               494.26
                   SAB NE 2/ENBRIDGE M                                                1,033            46.098742                47.62
                   SAB NE 2/STORAGE I                                                   425            46.847059                19.91
                   SAB NE 3/CENTANA#3 M                                               2,976            46.387769               138.05
                   SAB NE 3/ENBRIDGE E                                                  133            46.090226                 6.13
                   SAB NE 3/ENBRIDGE M                                                   52            47.307692                 2.46
                   SAB NE 3/TEJAS M                                                     425            46.117647                19.60
                   SAB NE 4/ENBRIDGE E                                                  425            44.894118                19.08
                   SAB NE 5/CENTANA#3 M                                                   8            47.500000                 0.38
                   SMEPA/WSPP B                                                       4,083            98.508450               402.21
                   SOUTHERN COMPANY SERVICES INC. AS                                220,624           127.999855            28,239.84
                   SUEZ Energy Marketing NA Inc./WSPP B                              49,501            51.789459             2,563.63
                   TENASKA/WSPP A                                                     4,956            60.831316               301.48
                   TENASKA/WSPP B                                                    24,226            63.290267             1,533.27
                   UNION POWER PARTNERS/WSPP B                                      109,867            52.567377             5,775.42
                   WESTAR ENERGY NC/WSPP B                                            1,810            49.248619                89.14
                   WILLOW GLEN 2/BL HOLDINGS E                                        1,912            45.000000                86.04
                   WILLOW GLEN 4/BL HOLDINGS E                                        1,742            45.975890                80.09

                   Totals                                                          1,590,958           68.949463           109,695.70




 Attachment Snapshot: 20100826181933                                RunID: 17029                                           Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                                 9-200
                                                                                                                           Exhibit PJC-2
                                                                                                                      2011 TX Rate Case
                                                                                                                           Page 39 of 70




 Entergy Electric System                                 Date range - 20100701 through 20100731                                            Attachment 3
 Intra-System Billing-201007RA                          Joint Account Delivery Sources - Summary                                                Page 39

                                        Source                               KWH                  Mills per KWH         Charge

                   Entergy Arkansas, Inc.                                             1,913,306           70.338498           134,579.07
                   Entergy Louisiana, LLC                                             2,774,712           72.052321           199,924.44
                   Entergy Mississippi, Inc.                                          1,549,246           77.384670           119,887.89
                   Entergy New Orleans, Inc.                                            431,606           69.237383            29,883.27
                   Entergy Gulf States Louisiana, LLC                                 1,912,208           68.251733           130,511.51
                   Entergy Texas, Inc                                                 1,590,958           68.949463           109,695.70

                   Totals                                                         10,172,036              71.222898           724,481.88




 Attachment Snapshot: 20100826181933                                   RunID: 17029                                           Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                                    9-201
                                                                                                                                      Exhibit PJC-2
                                                                                                                                 2011 TX Rate Case
                                                                                                                                      Page 40 of 70




 Entergy Electric System                                Date range - 20100701 through 20100731                                                         Attachment 3
 Intra-System Billing-201007RA                                  Joint Account Deliveries                                                                    Page 40

                                                                                                KWH            Cost
                                           Total Energy Supplied for
                                           Other Joint Account Sales                            10,172,036     724,481.88

                                           Cost to System for
                                           Other Joint Account Sales                                           724,481.88

                                           Total Billing to
                                           Other Joint Account Sales                                           635,035.41

                                           Net Balance From
                                           Other Joint Account Sales                                           (89,446.47)

                                           Total Net Balance                                                   (89,446.47)

                                           Total Net Balance - Demand                                                 0.00

                                           Total Net Balance - Energy                                          (89,446.47)




                                             Apportioning of Adjusted Net Balance from Joint Account Sales

                   Company                                                       Resp. Ratio                                       Net Balance

                   Entergy Arkansas, Inc.                                              0 2093    X           (89,446.47)     =           (18,721.14)
                   Entergy Louisiana, LLC                                              0 2511    X           (89,446.47)     =           (22,460.01)
                   Entergy Mississippi, Inc.                                           0.1399    X           (89,446.47)     =           (12,513.56)
                   Entergy New Orleans, Inc.                                           0 0447    X           (89,446.47)     =            (3,998.26)
                   Entergy Gulf States Louisiana, LLC                                  0.1893    X           (89,446.47)     =           (16,932.22)
                   Entergy Texas, Inc                                                  0.1657    X           (89,446.47)     =           (14,821.28)

                                                                                       1.0000                                            (89,446.47)




                                              Apportioning of Adjusted Net Balance - Demand and Energy
                   Company                                                                      Demand             Energy                    Total

                   Entergy Arkansas, Inc.                                                            0 00        (18,721.14)             (18,721.14)
                   Entergy Louisiana, LLC                                                            0 00        (22,460.01)             (22,460.01)
                   Entergy Mississippi, Inc.                                                         0 00        (12,513.56)             (12,513.56)
                   Entergy New Orleans, Inc.                                                         0 00         (3,998.26)              (3,998.26)
                   Entergy Gulf States Louisiana, LLC                                                0 00        (16,932.22)             (16,932.22)
                   Entergy Texas, Inc                                                                0 00        (14,821.28)             (14,821.28)

                   System                                                                            0.00        (89,446.47)             (89,446.47)




 Attachment Snapshot: 20100826181933                                    RunID: 17029                                                     Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                                               9-202
                                                                                                                               Exhibit PJC-2
                                                                                                                          2011 TX Rate Case
                                                                                                                               Page 41 of 70




 Entergy Electric System                            Date range - 20100701 through 20100731                                                      Attachment 4
 Intra-System Billing-201007RA                                 Coincident Peaks                                                                      Page 41



                                                       Full Load (including interruptible customers)

                    Year     Month     Day   Hour   System          AR           LA             MS         NO           EGSL          ETI
                    2009       7        2     16    20,266,591    4,076,854    5,207,236      2,960,570    960,099     3,864,047    3,197,785
                    2009       8        4     16    20,101,486    4,324,348    4,993,585      2,920,053    905,162     3,857,302    3,101,036
                    2009       9        8     16    17,789,153    3,869,828    4,425,469      2,654,403    762,423     3,416,026    2,661,004
                    2009      10        8     17    17,406,013    3,253,525    4,712,375      2,334,228    855,958     3,496,830    2,753,097
                    2009      11        17    19    13,100,671    3,023,242    3,553,282      1,773,843    558,074     2,316,730    1,875,500
                    2009      12        4     19    15,501,240    3,136,408    4,106,356      1,991,288    704,068     3,021,804    2,541,316
                    2010       1        8     8     18,693,431    3,945,217    4,824,812      2,386,441    857,848     3,136,742    3,542,371
                    2010       2       25     8     16,411,849    3,546,185    4,165,035      2,070,332    726,106     2,961,626    2,942,565
                    2010       3        3     7     15,338,210    3,137,824    4,034,685      1,929,748    712,963     2,858,148    2,664,842
                    2010       4       29     17    14,125,067    3,062,959    3,802,850      1,743,982    598,277     2,756,644    2,160,355
                    2010       5       24     15    18,755,924    3,909,082    5,001,840      2,640,718    858,007     3,356,689    2,989,588
                    2010       6       21     16    21,056,833    4,673,598    5,191,088      3,163,850    877,645     3,602,175    3,548,477

                   Total                                     0   43,959,070   54,018,613     28,569,456   9,376,630   38,644,763   33,977,936

                   12-Month Average                               3,663,255    4,501,551      2,380,788    781,385     3,220,396    2,831,494

                   Responsibility Ratio                             0.2108          0.2590      0.1370      0 0450       0.1853        0.1629




                                                         Load Excluding Interruptible Customers

                    Year     Month     Day   Hour   System          AR           LA             MS         NO           EGSL          ETI
                    2009       7        2     16    19,757,681    3,948,568    4,918,012      2,960,570    929,369     3,856,647    3,144,515
                    2009       8        4     16    19,684,363    4,238,659    4,759,049      2,920,053    883,034     3,834,101    3,049,467
                    2009       9        8     16    17,330,307    3,750,282    4,155,695      2,647,732    743,406     3,384,270    2,648,922
                    2009      10        8     17    17,055,723    3,223,627    4,459,097      2,329,371    841,486     3,469,237    2,732,905
                    2009      11        30    20    12,842,330    2,926,002    3,295,668      1,772,797    508,186     2,385,320    1,954,357
                    2009      12        4     19    15,184,415    3,136,164    3,881,283      1,967,199    683,654     2,998,563    2,517,552
                    2010       1        8     19    18,315,622    3,641,573    4,666,900      2,466,992    879,520     3,150,301    3,510,336
                    2010       2       25     7     16,157,950    3,426,523    4,006,582      2,070,845    703,193     2,989,430    2,961,377
                    2010       3        3     7     15,002,144    3,135,491    3,788,194      1,929,748    684,009     2,858,148    2,606,554
                    2010       4       29     17    13,729,642    2,925,536    3,610,881      1,743,982    577,503     2,729,585    2,142,155
                    2010       5       24     16    18,381,604    3,776,637    4,758,960      2,614,298    825,064     3,382,890    3,023,755
                    2010       6       21     16    20,563,419    4,569,484    4,921,567      3,124,114    860,795     3,570,306    3,517,153

                   Total                                     0   42,698,546   51,221,888     28,547,701   9,119,219   38,608,798   33,809,048

                   12-Month Average                               3,558,212    4,268,490      2,378,975    759,934     3,217,399    2,817,420

                   Responsibility Ratio                             0.2093          0.2511      0.1399      0 0447       0.1893        0.1657




 Attachment Snapshot: 20100826181933                                 RunID: 17029                                                  Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                                       9-203
                                                                                                                               Exhibit PJC-2
                                                                                                                          2011 TX Rate Case
                                                                                                                               Page 42 of 70




 Entergy Electric System                                Date range - 20100701 through 20100731                                                  Attachment 5
 Intra-System Billing-201007RA                      Service Schedule MSS - 1 / Reserve Equalization                                                  Page 42



                                 Source                System       AR            LA            MS          NO         EGSL           ETI

                   Owned Capability (A)

                   ANDRUS                                712 000       0.000        0.000        712 000      0.000        0.000        0.000
                   ANO                                 1,835 000   1,580.486       73.533         35.308     49.812       46.742       49.119
                   ATTALA                                455 000       0.000        0.000        455 000      0.000        0.000        0.000
                   BAXTER WILSON                       1,176 000       0.000        0.000      1,176 000      0.000        0.000        0.000
                   BIG CAJUN                             247 000       0.000        0.000          0 000      0.000      142.025      104.975
                   BURAS                                  12 000       0.000       12.000          0 000      0.000        0 000        0.000
                   CALCASIEU                             310 000       0.000        0.000          0 000      0.000      178.250      131.750
                   CARPENTER & REMMEL                     74 000      74.000        0.000          0 000      0.000        0.000        0.000
                   COUCH                                 123 000     123.000        0.000          0 000      0.000        0 000        0.000
                   DELTA                                 177 000       0.000        0.000        177 000      0.000        0.000        0.000
                   INDEPENDENCE                          682 840     226.815       10.563        424 561      7.163        6 699        7.039
                   LAKE CATHERINE                        712 000     712.000        0.000          0 000      0.000        0 000        0.000
                   LEWIS CREEK                           460 000       0.000        0.000          0 000      0.000      264.500      195.500
                   LITTLE GYPSY                        1,170 000       0.000    1,170.000          0 000      0.000        0.000        0.000
                   LYNCH                                 115 000     115.000        0.000          0 000      0.000        0 000        0.000
                   MABELVALE                              56 000      56.000        0.000          0 000      0.000        0.000        0.000
                   MICHOUD                               748 000       0.000        0.000          0 000    748.000        0.000        0.000
                   MOSES                                 134 000     134.000        0.000          0 000      0.000        0 000        0.000
                   NELSON                                988 000       0.000        0.000          0 000      0.000      568.100      419.900
                   NINEMILE PT.                        1,599 000       0.000    1,599.000          0 000      0.000        0.000        0.000
                   OUACHITA                              771 000     513.000        0.000          0 000      0.000      258 000        0.000
                   PERRYVILLE                            691 000       0.000      172.750          0 000      0.000      297 995      220.255
                   REX BROWN                             289 000       0.000        0.000        289 000      0.000        0.000        0.000
                   RITCHIE                                16 000      16.000        0.000          0 000      0.000        0.000        0.000
                   RIVERBEND                             681 800       0.000        0.000          0 000      0.000      392.035      289.765
                   SAB NE                              1,814 000       0.000        0.000          0 000      0.000    1,043.050      770.950
                   STERLINGTON                           174 000       0.000      174.000          0 000      0.000        0 000        0.000
                   WATERFORD                           2,021 000       0.000    2,021.000          0 000      0.000        0.000        0.000
                   WHITE BLUFF                           945 631     814.471       37.845         18.213     25.645       24.114       25.343
                   WILLOW GLEN                           817 000       0.000        0.000          0 000      0.000      469.775      347.225

                   Subtotal Owned Capability (A)      20,006.271   4,364.772    5,270.691      3,287.082    830.620    3,691.285   2,561.821


                   Capacity Purch. w/o (B)

                   ACADIAPOWERPARTNERS                   580 000      0.000       386.667         0 000       0.000     193 333         0.000
                   BLAKELY-ADD.                           11 000     11.000         0.000         0 000       0.000       0.000         0.000
                   CALPINE CARVILLE                      485 000      0.000         0.000         0 000       0.000     485.000         0.000
                   CONOCOPHIL PS-100                     100 000      0.000         0.000         0 000       0.000      57.500        42.500
                   CONOCOPHIL PS-SRW                     100 000      0.000         0.000         0 000       0.000       0.000       100.000
                   DEGRAY-ADD.                            10 000     10.000         0.000         0 000       0.000       0.000         0.000
                   DOW PIPELINE                          100 000      0.000         0.000         0 000       0.000      57.500        42.500
                   EPI ISES2                             121 000      0.000        61.105         0 000      59.895       0 000         0.000
                   ETEC HARD N                           146 000      0.000         0.000         0 000       0.000       0.000       146.000
                   ETEC HARRISON                          50 000      0.000         0.000         0 000       0.000       0.000        50.000
                   ETEC SAM RAYBURN                       34 667      0.000         0.000         0 000       0.000       0.000        34.667
                   ETEC SAN JACINTO                      146 000      0.000         0.000         0 000       0.000       0.000       146.000
                   ETEC W LLIS                             1 244      0.000         0.000         0 000       0.000       0.000         1.244
                   EXELON FRONTIER 10YR                  150 000      0.000         0.000         0 000       0.000       0.000       150.000
                   GRAND GULF #1                         992 878    272.302       157.626       371 550     191.400       0 000         0.000
                   GRAND GULF #1(RET/RP)                 133 023      0.000        39.380        17.831      27.408      23.603        24.801
                   MEAM                                   84 000      0.000         0.000        84.000       0.000       0.000         0.000
                   MURRAY HYDRO                          100 910      0.000       100.910         0 000       0.000       0 000         0.000
                   OCCIDENTAL-OXYTAFT                    480 000      0.000       480.000         0 000       0.000       0 000         0.000
                   RIVERBEND 30                          292 200      0.000       194.800         0 000      97.400       0 000         0.000
                   TOLEDO BEND                            69 000      0.000        23.000         0 000       0.000      26.450        19.550

                   Subtotal Capacity Purch. w/o (B)    4,186.922    293.302     1,443.488       473.381     376.103     843.386       757.262


                   Contract Capacity (D)

                   EXELON-150                            150 000     31.320           37.725     20.910       6.780      28.725        24.540

                   Subtotal Contract Capacity (D)        150.000     31.320           37.725     20.910       6.780      28.725        24.540


                   Totals                             24,343.193   4,689.394    6,751.904      3,781.373   1,213.503   4,563.396   3,343.623



 Attachment Snapshot: 20100826181933                                   RunID: 17029                                                Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                                        9-204
                                                                                                                               Exhibit PJC-2
                                                                                                                          2011 TX Rate Case
                                                                                                                               Page 43 of 70




 Entergy Electric System                            Date range - 20100701 through 20100731                                                    Attachment 5
 Intra-System Billing-201007RA                  Service Schedule MSS - 1 / Reserve Equalization                                                    Page 43



                                                                     AR              LA          MS            NO           EGSL             ETI

          A. Total Investment (Reserve Basis)                      (9 225500)     32.030600    41.588200     (17.393100) (10 568500)      64.834900
          B. Cost of Capital
             Debt Ratio                                             0.476500       0.502800     0.527000      0.455600      0.491300        0.483500
            x Bond Cost                                             0 061600       0.067100     0.063400      0.060700      0.060900        0 075100
            + Preferred Ratio                                       0 039300       0.019900     0.031800      0.047700      0.003200
            x Preferred Cost                                        0 059900       0.075500     0.056900      0.048200      0.087100
            + Common Ratio                                          0.484200       0.477400     0.441200      0.496700      0.505500        0 516500
            x Common Cost                                           0.110000       0.110000     0.110000      0.110000      0.110000        0.110000
           Total Cost of Capital                                    0 084968       0.087754     0.083753      0.084591      0.085804        0 093126
          E. Summary ($/KW)
           1. Cost of Money                                        (0.783872)      2.810813     3.483137     (1.471300)     (0 906820)     6 037815
           2. Depreciation                                          4 392930       5.463640     3.185940      7.406280       4.376400      5 651380
           3. Income Tax                                           (0 331149)      1.082090     1.296845     (0.619351)     (0 369380)     1 983494
           4. Insurance                                             0.473440       1.712090     1.516810      2.206730       0.485550      0 375450
           5. Property Tax                                          0.764290       1.219660     4.398050      2.406210       2.067020      1 890110
           6. Franchise Tax                                         0 031400                    0.194550      0.426430                     0.197930
           7. Operations & Maintenance + Overhead                  21.271470      22.889030    24.841370     34.298770     14.459670      24.806290

          Annual Cost per KW                                       25.818509      35.177323    38.916702     44.653769     20.112440      40.942469
          Monthly Cost per KW                                       2.151542       2.931444     3.243059      3.721147      1.676037       3.411872
          Monthly Cost $/MW                                             2,152          2,931        3,243         3,721        1,676           3,412

          System Capability (SC)                                  24,343.193

          Company Capability (CC)                                  4,689.394       6,751.904    3,781 373     1,213.503     4,563 396      3,343.623

          Required Capability (SC x CLR/SLR)                       5,095.062       6,112.120    3,406.493     1,088.162     4,607 046      4,034.310

          Equalization Reserve (ER = CC - SC x CLR/SLR)             (405.668)       639.784       374 880      125.341        (43.650)      (690.687)

          Allocation Factor                                           0.3558                                                   0.0383         0 6059

          Receipts                                                               1,875,205.93 1,215,735.84   466,393.86

          Payments                                               1,265,700.02                                              136,245.95 2,155,389.66




 Attachment Snapshot: 20100826181933                              RunID: 17029                                                   Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                                    9-205
                                                                                                                             Exhibit PJC-2
                                                                                                                        2011 TX Rate Case
                                                                                                                             Page 44 of 70




 Entergy Electric System                            Date range - 20100701 through 20100731                                                   Attachment 5
 Intra-System Billing-201007RA                Service Schedule MSS - 2 / Transmission Equalization                                                Page 44



                                                             AR              LA              MS             NO           EGSL              ETI

          Total Investment                              414,292,644.47 516,998,737.69   270,282,974.70 26,290,825 51 332,286,730.47   246,384,445.14
          Deferred Taxes                                 37,430,361.00 58,063,215.00    30,006,678.00 3,089,864.00 25,629,920 00      19,783,447 00
          Depreciation Reserve                          162,587,708.00 186,714,652.00   98,019,787.00 14,138,861 00 167,174,252.00    61,398,531 00
          Net Transmission Investment                   214,274,575.47 272,220,870.69   142,256,509.70 9,062,100.51 139,482,558.47    165,202,467.14

          Cost of Capital
            Debt Ratio (DR)                                  0.476500       0.502800        0.527000        0.455600      0.491300         0.483500
            Bond Cost (i)                                    0.061600       0.067100        0.063400        0.060700      0.060900         0 075100
            Preferred Ratio (PR)                             0.039300       0.019900        0.031800        0.047700      0.003200
            Preferred Cost (p)                               0.059900       0.075500        0.056900        0.048200      0.087100
            Common Ratio (ER)                                0.484200       0.477400        0.441200        0.496700      0.505500         0 516500
            Common Cost (c)                                  0.110000       0.110000        0.110000        0.110000      0.110000         0.110000
            Total Cost of Capital (CM)                       0.084968       0.087754        0.083753        0.084591      0.085804         0 093126

          Tax Rate (F)                                       0.035895       0.033783        0.031183        0.035609      0.034951         0 030593

          Operating Expenses
            Depreciation Factor (D)                        0.0153010       0 0271140       0.0229240       0.0277360     0.0202970       0.0197710
            Insurance Expense (I)                          0.0038030       0 0011480       0.0038520                     0.0021750       0.0018310
            Property Tax (PT)                              0.0043820       0 0082710       0.0166890       0.0121940     0.0067670       0.0074320
            Franchise Tax (FT)                             0.0001530                       0.0010110       0.0020450                     0.0008500
            Operations & Maintenance (OM)                  0.0351800       0 0374620       0.0356540       0.0424620     0.0448010       0.0263850
            Total Operating Expenses                       0.0588190       0 0739950       0.0801300       0.0844370     0.0740400       0.0562690

          Net Investment Ratio (K)                           0.517206       0.526541        0.526324        0.344687      0.419766         0 670507

          Annual Ownership Cost                              0.234587       0.262067        0.267180        0.365167      0.297138         0 207639

          Net Transmission Investment * AOC             50,266,030.00 71,340,107.00 38,008,094.00        3,309,180.00 41,445,568 00 34,302,475 00

          System Average Annual Ownership Cost          238,671,454.00 /       942,499,081.98        =     0.2532326

          System Average Monthly Ownership Cost                                     0.2532326     / 12     0.0211027

          Responsibility Ratio                                 0.2108          0.2590           0.1370        0.0450        0.1853           0.1629

          Transmission Responsibility                   198,678,806.48 244,107,262.23 129,122,374.23 42,412,458 69 174,645,079.89 153,533,100.45

          Investment Difference                         15,595,768.99 28,113,608.46 13,134,135.47 (33,350,358.18) (35,162,521.42) 11,669,366 69

          Payments                                                                                        703,783.04    742,024.61

          Receipts                                         329,113.04      593,273.42      277,165.89                                    246,255.30




 Attachment Snapshot: 20100826181933                                RunID: 17029                                                Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                                     9-206
                                                                                                                     Exhibit PJC-2
                                                                                                                2011 TX Rate Case
                                                                                                                     Page 45 of 70




 Entergy Electric System                            Date range - 20100701 through 20100731                                       Attachment 6-AR
 Intra-System Billing-201007RA                     Company Summary - Entergy Arkansas, Inc.                                              Page 45



                                                                       Sales(KWH)        Purchases(KWH)    Revenue($)              Expense($)

 Purchases and Sales - Associated Companies

 Exchange Energy                                                           131,743,223       131,563,443       5,265,506.15              8,545,539.76
 Tele. AECC Excess Energy                                                   45,883,356                 0       1,511,948.91                      0.00
 ARK.NU 1 Desig. Energy                                                     86,421,339                 0               0.00                      0.00
 ARK.NU 2 Desig. Energy                                                    102,307,792                 0               0.00                      0.00
 GGULF RET Desig. Energy                                                    66,088,728                 0               0.00                      0.00
 GGULF RP Desig. Energy                                                     32,499,259                 0               0.00                      0.00
 INDEPN 1 Desig. Energy                                                     24,696,343                 0               0.00                      0.00
 WH.BLF 1 Desig. Energy                                                     45,314,539                 0               0.00                      0.00
 WH.BLF 2 Desig. Energy                                                     38,134,556                 0               0.00                      0.00
 Equalized Res. Charge                                                               0                 0               0.00              1,265,700.02
 Trans. Equal. Charge                                                                0                 0               0.00               (329,113.04)
 Fiber Optic Equalization                                                            0                 0               0.00                 45,958.19
 Bandwidth Pymt/Receipt-Opinion Nos. 480 & 480-A                                     0                 0               0.00              3,905,000.00

 Subtotal Purchases and Sales - Associated Companies                       573,089,135       131,563,443       6,777,455.06            13,433,084.93



 Non-Associated Companies - Joint Account Sales                        Sales(KWH)        Purchases(KWH)    Revenue($)              Expense($)

 Net Balance for Sales                                                               0                0         (18,721.14)                        0.00
 Energy Supp. for Sales                                                      1,913,306                0         134,579.07                         0.00
 AIR LIQUIDE AMERICA - ANN FEE                                                       0                0           2,093.00                         0.00
 BASF CORPORATION - ANN FEE                                                          0                0           2,093.00                         0.00
 CENTRAL LA ELEC CO ENG CHG ADJ - REVENUE                                            0                0              (0.01)                        0.00
 COTTONWOOD ENERGY CO - GEN REG                                                      0                0           4,911.95                         0.00
 CYPRES - GEN REG                                                                    0                0           8,479.13                         0.00
 DOW CHEMICAL - ANN FEE                                                              0                0           2,093.00                         0.00
 DUKE ENERGY HINDS - GEN REG                                                         0                0           3,671.18                         0.00
 DUKEENERGY HOTSPRING - GEN REG                                                      0                0           8,791.81                         0.00
 FORMOSA PLASTICS - ANN FEE                                                          0                0           2,093.00                         0.00
 GRAND RIVER DAM AUTHORITY ENG CHG ADJ - REVENUE                                     0                0              (0.05)                        0.00
 HUNTSMAN P.N. - ANN FEE                                                             0                0           2,093.00                         0.00
 KANSAS CITY POWER & LIGHT COMP ENG CHG ADJ - REVENUE                                0                0               0.03                         0.00
 MAGNET COVE - GEN REG                                                               0                0           1,740.09                         0.00
 MDEA CROSSROADS - GEN REG                                                           0                0             744.10                         0.00
 MISSOURI PUBLIC SERVICE ENG CHG ADJ - REVENUE                                       0                0               0.04                         0.00
 NEBRASKA PUBLIC POWER DISTRICT ENG CHG ADJ - REVENUE                                0                0              (0.05)                        0.00
 OCCIDENTAL CHEM CORP - GEN REG                                                      0                0           1,164.71                         0.00
 PINE BLUFF ENERGY - GEN REG                                                         0                0               0.51                         0.00
 PPG INDUSTR ES - ANN FEE                                                            0                0           2,093.00                         0.00
 SRW COGENERATION - GEN REG                                                          0                0             682.53                         0.00
 TENASKA FRONTIER - GEN REG                                                          0                0           3,280.86                         0.00
 UNION CARBIDE CORP - ANN FEE                                                        0                0           2,093.00                         0.00
 WRIGHTSVILE POWER - GEN REG                                                         0                0           4,452.16                         0.00
 YAZOO CITY - GEN REG                                                                0                0               2.49                         0.00

 Subtotal Non-Associated Companies - Joint Account Sales                     1,913,306                0         168,430.41                         0.00



 Non-Associated Companies - Joint Account Purchases                    Sales(KWH)        Purchases(KWH)    Revenue($)              Expense($)

 AECI RE Energy                                                                     0         14,296,119                0.00               610,073.17
 AEP SERVICE CORP. RE Energy                                                        0            793,440                0.00                27,039.59
 AMEREN ENERGY NC. (AE) ACTING RE Energy                                            0            501,120                0.00                24,554.89
 Ameren Energy Marketing Company RE Energy                                          0             10,440                0.00                   334.08
 BNP PARIBAS ENERGY TRADING GP RE Energy                                            0            845,431                0.00                45,316.99
 CALP NE ENERGY SERVICES L.P. RE Energy                                             0          2,789,568                0.00               146,243.56
 CARGILL POWER MARKETS LLC RE Energy                                                0            349,740                0.00                 9,888.24
 CITIGROUP ENERGY NC RE Energy                                                      0             50,112                0.00                 1,681.88
 CLECO RE Energy                                                                    0          1,048,172                0.00                66,267.70
 CONSTELLATION ENERGY COMMODITIES GROUP INC RE Energy                               0          1,172,829                0.00                48,758.64
 COTTONWOOD ENERGY CO RE Energy                                                     0            783,233                0.00                30,180.30
 CYPRES RE Energy                                                                   0             30,648                0.00                 1,267.50
 DB ENERGY TRAD NG LLC RE Energy                                                    0         21,593,680                0.00             1,102,783.95
 DUKE ENERGY HINDS RE Energy                                                        0            221,754                0.00                 8,431.92
 DUKEENERGY HOTSPRING RE Energy                                                     0            199,789                0.00                 7,436.91
 ENDURE ENERGY RE Energy                                                            0            297,537                0.00                13,904.44
 ETEC RE Energy                                                                     0            244,298                0.00                10,993.46
 EXELON GENERATION COMPANY LLC RE Energy                                            0         19,524,239                0.00               809,340.37
 Attachment Snapshot: 20100826181933                              RunID: 17029                                           Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                             9-207
                                                                                                                  Exhibit PJC-2
                                                                                                             2011 TX Rate Case
                                                                                                                  Page 46 of 70




 Entergy Electric System                       Date range - 20100701 through 20100731                                         Attachment 6-AR
 Intra-System Billing-201007RA                Company Summary - Entergy Arkansas, Inc.                                                Page 46

                                                                    Sales(KWH)        Purchases(KWH)    Revenue($)              Expense($)

 J ARON & COMPANY RE Energy                                                      0          4,984,056                0.00               256,121.06
 J.P. MORGAN VENTURES ENERGY CORPORATION RE Energy                               0          1,033,979                0.00                69,555.14
 JBO RE Energy                                                                   0          4,187,691                0.00               275,806.37
 KANSAS CITY POWER & LIGHT COMPANY RE Energy                                     0            300,881                0.00                 8,339.06
 MAGNET COVE RE Energy                                                           0          1,069,515                0.00                39,180.42
 MDEA CROSSROADS RE Energy                                                       0             40,084                0.00                 1,700.80
 MERRILL LYNCH COMMODITIES INC RE Energy                                         0         40,521,612                0.00             1,994,933.07
 MORGAN STANLEY RE Energy                                                        0             51,366                0.00                 1,223.18
 NRG POWER MARKETING LLC. RE Energy                                              0         46,561,153                0.00             2,253,552.56
 OCCIDENTAL POWER SERVICES RE Energy                                             0          1,189,742                0.00                75,381.01
 RAINBOW ENERGY MARKETING CORP RE Energy                                         0          2,907,333                0.00                93,375.97
 SMEPA RE Energy                                                                 0            626,400                0.00                55,914.95
 SOUTHERN COMPANY SERVICES INC. AS AGENT FO RE Energy                            0          2,328,120                0.00               287,663.83
 SUEZ Energy Marketing NA Inc. RE Energy                                         0         13,613,136                0.00               646,652.75
 TEA RE Energy                                                                   0            233,021                0.00                 6,829.44
 TENASKA FRONTIER RE Energy                                                      0            248,836                0.00                 9,376.03
 TENASKA RE Energy                                                               0          5,303,526                0.00               318,688.60
 UNION POWER PARTNERS RE Energy                                                  0         34,436,751                0.00             1,728,653.96
 WESTAR ENERGY NC RE Energy                                                      0          7,784,895                0.00               270,527.41
 WRIGHTSVILE POWER RE Energy                                                     0            177,550                0.00                 7,503.15
 YAZOO CITY RE Energy                                                            0              1,101                0.00                    48.70
 ENG ADJ - EXPENSE                                                               0                  0                0.00                    (0.01)
 EXELON 150 1YR- CAP CHG                                                         0                  0                0.00               343,658.70
 EXELON GENERATION COMPANY LLC ENG CHG ADJ - EXPENSE                             0                  0                0.00                    (0.01)
 JAP - DB ENERGY ENG CHG                                                         0                  0                0.00                    (0.07)
 JAP - EXELON ENG CHG                                                            0                  0                0.00                    (0.15)
 JAP - MLCI ENG CHG                                                              0                  0                0.00                    (0.20)
 JAP - NRG ENG CHG                                                               0                  0                0.00                    (0.21)
 JAP - SUEZ ENG CHG                                                              0                  0                0.00                    (0.04)
 JAP - UNION ENG CHG                                                             0                  0                0.00                    (0.16)
 MERRILL LYNCH COMMODITIES ENG CHG ADJ - EXPENSE                                 0                  0                0.00                     0.20
 SWPP RESER - CAP CHG                                                            0                  0                0.00                   626.40
 SWPP TARIFF CHG                                                                 0                  0                0.00                   152.23
 UNION POWER PARTNERS LP ENG CHG ADJ - EXPENSE                                   0                  0                0.00                    (0.10)

 Subtotal Non-Associated Companies - Joint Account Purchases                     0        232,352,897                0.00           11,709,961.63


 Totals                                                                 575,002,441       363,916,340       6,945,885.47            25,143,046.56

 ESI Receivable from Entergy Arkansas, Inc.                                                                                         18,197,161.09




 Attachment Snapshot: 20100826181933                           RunID: 17029                                           Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                          9-208
                                                                                                                Exhibit PJC-2
                                                                                                           2011 TX Rate Case
                                                                                                                Page 47 of 70




 Entergy Electric System                        Date range - 20100701 through 20100731                                      Attachment 6-LA
 Intra-System Billing-201007RA                Company Summary - Entergy Louisiana, LLC                                             Page 47



                                                                  Sales(KWH)        Purchases(KWH)    Revenue($)              Expense($)

 Purchases and Sales - Associated Companies

 Exchange Energy                                                      135,105,357        42,272,082     10,226,157.06               2,134,170.65
 Tele. AECC Excess Energy                                                       0        14,584,886              0.00                 480,598.16
 ARK.NU 1 - UPP from AR Desig. Energy                                           0        24,991,859              0.00                       0.00
 ARK.NU 2 - UPP from AR Desig. Energy                                           0        29,534,318              0.00                       0.00
 GGULF RET - UPP from AR Desig. Energy                                          0        19,691,908              0.00                       0.00
 GGULF RP - UPP from AR Desig. Energy                                           0         9,494,456              0.00                       0.00
 INDEPN 1 - UPP from AR Desig. Energy                                           0         7,145,175              0.00                       0.00
 RVRBND 1 - UPP from EGSL Desig. Energy                                         0       139,555,800              0.00                       0.00
 WH.BLF 1 - UPP from AR Desig. Energy                                           0        13,440,805              0.00                       0.00
 WH.BLF 2 - UPP from AR Desig. Energy                                           0        10,706,289              0.00                       0.00
 ACADIA POWER PARTNERS, LLC/WSPP B Desig. Energy                       59,708,320                 0              0.00                       0.00
 PERVIL 1 Desig. Energy                                               194,914,500                 0              0.00                       0.00
 Equalized Res. Charge                                                          0                 0      1,875,205.93                       0.00
 Trans. Equal. Charge                                                           0                 0              0.00                (593,273.42)
 Fiber Optic Equalization                                                       0                 0              0.00                  13,548.63
 Bandwidth Pymt/Receipt-Opinion Nos. 480 & 480-A                                0                 0      1,843,000.00                       0.00

 Subtotal Purchases and Sales - Associated Companies                  389,728,177       311,417,578     13,944,362.99               2,035,044.02



 Non-Associated Companies - Joint Account Sales                   Sales(KWH)        Purchases(KWH)    Revenue($)              Expense($)

 Net Balance for Sales                                                          0                0         (22,460.01)                        0.00
 Energy Supp. for Sales                                                 2,774,712                0         199,924.44                         0.00
 AIR LIQUIDE AMERICA - ANN FEE                                                  0                0           2,511.00                         0.00
 BASF CORPORATION - ANN FEE                                                     0                0           2,511.00                         0.00
 CENTRAL LA ELEC CO ENG CHG ADJ - REVENUE                                       0                0              (0.01)                        0.00
 COTTONWOOD ENERGY CO - GEN REG                                                 0                0           5,892.94                         0.00
 CYPRES - GEN REG                                                               0                0          10,172.52                         0.00
 DOW CHEMICAL - ANN FEE                                                         0                0           2,511.00                         0.00
 DUKE ENERGY HINDS - GEN REG                                                    0                0           4,404.37                         0.00
 DUKEENERGY HOTSPRING - GEN REG                                                 0                0          10,547.65                         0.00
 FORMOSA PLASTICS - ANN FEE                                                     0                0           2,511.00                         0.00
 GRAND RIVER DAM AUTHORITY ENG CHG ADJ - REVENUE                                0                0              (0.06)                        0.00
 HUNTSMAN P.N. - ANN FEE                                                        0                0           2,511.00                         0.00
 KANSAS CITY POWER & LIGHT COMP ENG CHG ADJ - REVENUE                           0                0               0.04                         0.00
 MAGNET COVE - GEN REG                                                          0                0           2,087.62                         0.00
 MDEA CROSSROADS - GEN REG                                                      0                0             892.70                         0.00
 MISSOURI PUBLIC SERVICE ENG CHG ADJ - REVENUE                                  0                0               0.05                         0.00
 NEBRASKA PUBLIC POWER DISTRICT ENG CHG ADJ - REVENUE                           0                0              (0.06)                        0.00
 OCCIDENTAL CHEM CORP - GEN REG                                                 0                0           1,397.32                         0.00
 PINE BLUFF ENERGY - GEN REG                                                    0                0               0.62                         0.00
 PPG INDUSTR ES - ANN FEE                                                       0                0           2,511.00                         0.00
 SOUTHWEST POWER ADMN ENG CHG ADJ - REVENUE                                     0                0              (0.01)                        0.00
 SRW COGENERATION - GEN REG                                                     0                0             818.84                         0.00
 TENASKA FRONTIER - GEN REG                                                     0                0           3,936.09                         0.00
 UNION CARBIDE CORP - ANN FEE                                                   0                0           2,511.00                         0.00
 WRIGHTSVILE POWER - GEN REG                                                    0                0           5,341.31                         0.00
 YAZOO CITY - GEN REG                                                           0                0               2.99                         0.00

 Subtotal Non-Associated Companies - Joint Account Sales                2,774,712                0         240,536.35                         0.00



 Non-Associated Companies - Joint Account Purchases               Sales(KWH)        Purchases(KWH)    Revenue($)              Expense($)

 ACADIA POWER PARTNERS, LLC RE Energy                                          0        179,125,000                0.00             6,106,961.20
 AECI RE Energy                                                                0         17,219,703                0.00               734,834.42
 AEP SERVICE CORP. RE Energy                                                   0            955,700                0.00                32,569.33
 AMEREN ENERGY NC. (AE) ACTING RE Energy                                       0            603,600                0.00                29,576.40
 Ameren Energy Marketing Company RE Energy                                     0             12,575                0.00                   402.40
 BNP PARIBAS ENERGY TRADING GP RE Energy                                       0          1,018,324                0.00                54,584.38
 BURAS TEMP RE Energy                                                          0            131,908                0.00                34,364.05
 CALP NE ENERGY SERVICES L.P. RE Energy                                        0          3,360,048                0.00               176,151.06
 CARGILL POWER MARKETS LLC RE Energy                                           0            421,265                0.00                11,910.49
 CITIGROUP ENERGY NC RE Energy                                                 0             60,361                0.00                 2,025.87
 CLECO RE Energy                                                               0          1,262,618                0.00                79,826.20
 CONSTELLATION ENERGY COMMODITIES GROUP INC RE Energy                          0          1,412,677                0.00                58,730.23
 COTTONWOOD ENERGY CO RE Energy                                                0            943,361                0.00                36,350.30
 CYPRES RE Energy                                                              0             36,913                0.00                 1,526.56
 Attachment Snapshot: 20100826181933                         RunID: 17029                                           Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                        9-209
                                                                                                                   Exhibit PJC-2
                                                                                                              2011 TX Rate Case
                                                                                                                   Page 48 of 70




 Entergy Electric System                        Date range - 20100701 through 20100731                                         Attachment 6-LA
 Intra-System Billing-201007RA                Company Summary - Entergy Louisiana, LLC                                                Page 48

                                                                    Sales(KWH)        Purchases(KWH)     Revenue($)              Expense($)

 DB ENERGY TRAD NG LLC RE Energy                                                 0         26,009,688                 0.00            1,328,308.08
 DUKE ENERGY HINDS RE Energy                                                     0            267,110                 0.00               10,156.10
 DUKEENERGY HOTSPRING RE Energy                                                  0            240,658                 0.00                8,957.84
 ENDURE ENERGY RE Energy                                                         0            358,396                 0.00               16,748.60
 ETEC RE Energy                                                                  0            294,260                 0.00               13,241.70
 EXELON GENERATION COMPANY LLC RE Energy                                         0         23,517,077                 0.00              974,855.35
 J ARON & COMPANY RE Energy                                                      0          6,003,359                 0.00              308,501.05
 J.P. MORGAN VENTURES ENERGY CORPORATION RE Energy                               0          1,245,433                 0.00               83,779.48
 JBO RE Energy                                                                   0          5,044,138                 0.00              332,212.21
 KANSAS CITY POWER & LIGHT COMPANY RE Energy                                     0            362,411                 0.00               10,044.40
 MAGNET COVE RE Energy                                                           0          1,288,274                 0.00               47,194.28
 MDEA CROSSROADS RE Energy                                                       0             48,272                 0.00                2,048.17
 MERRILL LYNCH COMMODITIES INC RE Energy                                         0         48,808,429                 0.00            2,402,903.87
 MORGAN STANLEY RE Energy                                                        0             61,868                 0.00                1,473.28
 NRG POWER MARKETING LLC. RE Energy                                              0         56,083,268                 0.00            2,714,420.29
 OCCIDENTAL POWER SERVICES RE Energy                                             0        280,091,048                 0.00           10,465,221.67
 RAINBOW ENERGY MARKETING CORP RE Energy                                         0          3,501,908                 0.00              112,472.37
 SMEPA RE Energy                                                                 0            754,504                 0.00               67,350.01
 SOUTHERN COMPANY SERVICES INC. AS AGENT FO RE Energy                            0          2,804,225                 0.00              346,491.54
 SUEZ Energy Marketing NA Inc. RE Energy                                         0         16,397,077                 0.00              778,895.88
 TEA RE Energy                                                                   0            280,677                 0.00                8,226.15
 TENASKA FRONTIER RE Energy                                                      0            299,738                 0.00               11,293.95
 TENASKA RE Energy                                                               0          6,388,123                 0.00              383,862.17
 UNION POWER PARTNERS RE Energy                                                  0         41,479,230                 0.00            2,082,171.87
 WESTAR ENERGY NC RE Energy                                                      0          9,376,942                 0.00              325,851.13
 WRIGHTSVILE POWER RE Energy                                                     0            213,842                 0.00                9,036.81
 YAZOO CITY RE Energy                                                            0              1,324                 0.00                   58.57
 ACADIA POWER PARTNERS ENG CHG ADJ - EXPENSE                                     0                  0                 0.00                   14.83
 ACADIA PPA - 580 MW - CAP CHG                                                   0                  0                 0.00              714,364.24
 ACADIA PPA - 580 MW -START CHG                                                  0                  0                 0.00              930,785.87
 ACADIA PPA - 580 MW -VOM CHG                                                    0                  0                 0.00              199,376.00
 EXELON 150 1YR- CAP CHG                                                         0                  0                 0.00              413,937.56
 EXELON GENERATION COMPANY LLC ENG CHG ADJ - EXPENSE                             0                  0                 0.00                   (0.01)
 JAP - ACADIA ENG CHG                                                            0                  0                 0.00                   (0.62)
 JAP - DB ENERGY ENG CHG                                                         0                  0                 0.00                   (0.08)
 JAP - EXELON ENG CHG                                                            0                  0                 0.00                   (0.18)
 JAP - MLCI ENG CHG                                                              0                  0                 0.00                   (0.25)
 JAP - NRG ENG CHG                                                               0                  0                 0.00                   (0.26)
 JAP - OXY ENG CHG                                                               0                  0                 0.00                   (4.79)
 JAP - SUEZ ENG CHG                                                              0                  0                 0.00                   (0.05)
 JAP - UNION ENG CHG                                                             0                  0                 0.00                   (0.20)
 MERRILL LYNCH COMMODITIES ENG CHG ADJ - EXPENSE                                 0                  0                 0.00                    0.24
 OCCIDENTAL POWER SERVICES NC. - STARTUP CHG - 0                                 0                  0                 0.00              231,750.00
 OCCIDENTAL POWER SERVICES NC. ENG CHG ADJ - EXPENSE                             0                  0                 0.00                   (0.29)
 OCCIDENTIAL - 480MW - CAP CHG                                                   0                  0                 0.00            3,399,552.43
 SWPP RESER - CAP CHG                                                            0                  0                 0.00                  754.50
 SWPP TARIFF CHG                                                                 0                  0                 0.00                  183.36
 UNION POWER PARTNERS LP ENG CHG ADJ - EXPENSE                                   0                  0                 0.00                   (0.11)

 Subtotal Non-Associated Companies - Joint Account Purchases                     0        737,785,332                 0.00           36,096,301.90



 Transmission Service                                               Sales(KWH)        Purchases(KWH)     Revenue($)              Expense($)

 CLECO TRAN SERV CHG                                                             0                  0                 0.00               104,767.78

 Subtotal Transmission Service                                                   0                  0                 0.00               104,767.78


 Totals                                                                 392,502,889      1,049,202,910     14,184,899.34             38,236,113.70

 ESI Receivable from Entergy Louisiana, LLC                                                                                          24,051,214.36




 Attachment Snapshot: 20100826181933                           RunID: 17029                                            Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                           9-210
                                                                                                                       Exhibit PJC-2
                                                                                                                  2011 TX Rate Case
                                                                                                                       Page 49 of 70




 Entergy Electric System                             Date range - 20100701 through 20100731                                        Attachment 6-MS
 Intra-System Billing-201007RA                     Company Summary - Entergy Mississippi, Inc.                                             Page 49



                                                                         Sales(KWH)        Purchases(KWH)    Revenue($)              Expense($)

 Purchases and Sales - Associated Companies

 Exchange Energy                                                              32,027,550       165,417,337       2,046,403.14            10,587,664.98
 Tele. AECC Excess Energy                                                              0         8,083,973               0.00               266,379.39
 ARK.NU 1 - UPP from AR Desig. Energy                                                  0        11,975,579               0.00                     0.00
 ARK.NU 2 - UPP from AR Desig. Energy                                                  0        14,206,469               0.00                     0.00
 GGULF RET - UPP from AR Desig. Energy                                                 0         8,775,642               0.00                     0.00
 GGULF RP - UPP from AR Desig. Energy                                                  0         4,440,083               0.00                     0.00
 INDEPN 1 - UPP from AR Desig. Energy                                                  0         3,421,107               0.00                     0.00
 WH.BLF 1 - UPP from AR Desig. Energy                                                  0         6,292,389               0.00                     0.00
 WH.BLF 2 - UPP from AR Desig. Energy                                                  0         5,295,338               0.00                     0.00
 Equalized Res. Charge                                                                 0                 0       1,215,735.84                     0.00
 Trans. Equal. Charge                                                                  0                 0               0.00              (277,165.89)
 Fiber Optic Equalization                                                              0                 0               0.00               (77,957.98)
 Bandwidth Pymt/Receipt-Opinion Nos. 480 & 480-A                                       0                 0       2,062,000.00                     0.00

 Subtotal Purchases and Sales - Associated Companies                          32,027,550       227,907,917       5,324,138.98            10,498,920.50



 Non-Associated Companies - Joint Account Sales                          Sales(KWH)        Purchases(KWH)    Revenue($)              Expense($)

 Net Balance for Sales                                                                 0                0         (12,513.56)                        0.00
 Energy Supp. for Sales                                                        1,549,246                0         119,887.89                         0.00
 AIR LIQUIDE AMERICA - ANN FEE                                                         0                0           1,399.00                         0.00
 BASF CORPORATION - ANN FEE                                                            0                0           1,399.00                         0.00
 COTTONWOOD ENERGY CO - GEN REG                                                        0                0           3,283.24                         0.00
 CYPRES - GEN REG                                                                      0                0           5,667.60                         0.00
 DOW CHEMICAL - ANN FEE                                                                0                0           1,399.00                         0.00
 DUKE ENERGY HINDS - GEN REG                                                           0                0           2,453.89                         0.00
 DUKEENERGY HOTSPRING - GEN REG                                                        0                0           5,876.61                         0.00
 FORMOSA PLASTICS - ANN FEE                                                            0                0           1,399.00                         0.00
 GRAND RIVER DAM AUTHORITY ENG CHG ADJ - REVENUE                                       0                0              (0.04)                        0.00
 HUNTSMAN P.N. - ANN FEE                                                               0                0           1,399.00                         0.00
 KANSAS CITY POWER & LIGHT COMP ENG CHG ADJ - REVENUE                                  0                0               0.02                         0.00
 MAGNET COVE - GEN REG                                                                 0                0           1,163.11                         0.00
 MDEA CROSSROADS - GEN REG                                                             0                0             497.37                         0.00
 MISSOURI PUBLIC SERVICE ENG CHG ADJ - REVENUE                                         0                0               0.03                         0.00
 NEBRASKA PUBLIC POWER DISTRICT ENG CHG ADJ - REVENUE                                  0                0              (0.04)                        0.00
 OCCIDENTAL CHEM CORP - GEN REG                                                        0                0             778.51                         0.00
 PINE BLUFF ENERGY - GEN REG                                                           0                0               0.34                         0.00
 PPG INDUSTR ES - ANN FEE                                                              0                0           1,399.00                         0.00
 SRW COGENERATION - GEN REG                                                            0                0             456.21                         0.00
 TENASKA FRONTIER - GEN REG                                                            0                0           2,192.99                         0.00
 UNION CARBIDE CORP - ANN FEE                                                          0                0           1,399.00                         0.00
 WRIGHTSVILE POWER - GEN REG                                                           0                0           2,975.90                         0.00
 YAZOO CITY - GEN REG                                                                  0                0               1.67                         0.00

 Subtotal Non-Associated Companies - Joint Account Sales                       1,549,246                0         142,514.74                         0.00



 Non-Associated Companies - Joint Account Purchases                      Sales(KWH)        Purchases(KWH)    Revenue($)              Expense($)

 AECI RE Energy                                                                       0          9,544,439                0.00               407,299.61
 AEP SERVICE CORP. RE Energy                                                          0            529,720                0.00                18,052.30
 AMEREN ENERGY NC. (AE) ACTING RE Energy                                              0            334,560                0.00                16,393.44
 Ameren Energy Marketing Company RE Energy                                            0              6,970                0.00                   223.04
 BNP PARIBAS ENERGY TRADING GP RE Energy                                              0            564,431                0.00                30,254.63
 CALP NE ENERGY SERVICES L.P. RE Energy                                               0          1,862,384                0.00                97,635.84
 CARGILL POWER MARKETS LLC RE Energy                                                  0            233,494                0.00                 6,601.61
 CITIGROUP ENERGY NC RE Energy                                                        0             33,456                0.00                 1,122.87
 CLECO RE Energy                                                                      0            699,790                0.00                44,242.50
 CONSTELLATION ENERGY COMMODITIES GROUP INC RE Energy                                 0            783,010                0.00                32,552.49
 COTTONWOOD ENERGY CO RE Energy                                                       0            522,874                0.00                20,147.91
 CYPRES RE Energy                                                                     0             20,463                0.00                   846.28
 DB ENERGY TRAD NG LLC RE Energy                                                      0         14,416,465                0.00               736,245.05
 DUKE ENERGY HINDS RE Energy                                                          0            147,968                0.00                 5,625.85
 DUKEENERGY HOTSPRING RE Energy                                                       0            133,374                0.00                 4,964.61
 ENDURE ENERGY RE Energy                                                              0            198,650                0.00                 9,283.31
 ETEC RE Energy                                                                       0            163,098                0.00                 7,339.39
 EXELON GENERATION COMPANY LLC RE Energy                                              0         13,034,879                0.00               540,336.52
 J ARON & COMPANY RE Energy                                                           0          3,327,478                0.00               170,992.64
 Attachment Snapshot: 20100826181933                                RunID: 17029                                           Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                               9-211
                                                                                                                     Exhibit PJC-2
                                                                                                                2011 TX Rate Case
                                                                                                                     Page 50 of 70




 Entergy Electric System                           Date range - 20100701 through 20100731                                        Attachment 6-MS
 Intra-System Billing-201007RA                   Company Summary - Entergy Mississippi, Inc.                                             Page 50

                                                                       Sales(KWH)        Purchases(KWH)    Revenue($)              Expense($)

 J.P. MORGAN VENTURES ENERGY CORPORATION RE Energy                                  0            690,309                0.00                46,436.66
 JBO RE Energy                                                                      0          2,795,808                0.00               184,135.12
 KANSAS CITY POWER & LIGHT COMPANY RE Energy                                        0            200,875                0.00                 5,567.35
 MAGNET COVE RE Energy                                                              0            714,090                0.00                26,159.84
 MDEA CROSSROADS RE Energy                                                          0             26,755                0.00                 1,135.26
 MEAM CANTON 1 IN RE Energy                                                         0             73,000                0.00                 8,826.43
 MEAM CANTON 2 IN RE Energy                                                         0             83,000                0.00                10,035.53
 MEAM CANTON 3 IN RE Energy                                                         0             84,000                0.00                10,156.44
 MEAM CANTON 4 IN RE Energy                                                         0             84,000                0.00                10,156.44
 MEAM CANTON 5 IN RE Energy                                                         0             82,000                0.00                 9,914.62
 MEAM HENDERSON 10 IN RE Energy                                                     0             58,000                0.00                 7,012.78
 MEAM HENDERSON 11 IN RE Energy                                                     0             59,000                0.00                 7,133.69
 MEAM HENDERSON 2 IN RE Energy                                                      0            524,000                0.00                63,355.61
 MEAM HENDERSON 4 IN RE Energy                                                      0             72,000                0.00                 8,705.52
 MEAM HENDERSON 5 IN RE Energy                                                      0             72,000                0.00                 8,705.52
 MEAM HENDERSON 6 IN RE Energy                                                      0             73,000                0.00                 8,826.43
 MEAM HENDERSON 7 IN RE Energy                                                      0             76,000                0.00                 9,189.16
 MEAM HENDERSON 8 IN RE Energy                                                      0             74,000                0.00                 8,947.34
 MEAM HENDERSON 9 IN RE Energy                                                      0             54,000                0.00                 6,529.14
 MERRILL LYNCH COMMODITIES INC RE Energy                                            0         27,053,226                0.00             1,331,865.81
 MORGAN STANLEY RE Energy                                                           0             34,292                0.00                   816.61
 NRG POWER MARKETING LLC. RE Energy                                                 0         31,085,352                0.00             1,504,525.39
 OCCIDENTAL POWER SERVICES RE Energy                                                0            794,302                0.00                50,326.31
 RAINBOW ENERGY MARKETING CORP RE Energy                                            0          1,941,010                0.00                62,340.08
 SMEPA RE Energy                                                                    0            418,200                0.00                37,330.24
 SOUTHERN COMPANY SERVICES INC. AS AGENT FO RE Energy                               0          1,554,310                0.00               192,051.39
 SUEZ Energy Marketing NA Inc. RE Energy                                            0          9,088,455                0.00               431,720.89
 TEA RE Energy                                                                      0            155,570                0.00                 4,559.48
 TENASKA FRONTIER RE Energy                                                         0            166,087                0.00                 6,258.00
 TENASKA RE Energy                                                                  0          3,540,763                0.00               212,764.09
 UNION POWER PARTNERS RE Energy                                                     0         22,990,829                0.00             1,154,092.08
 WESTAR ENERGY NC RE Energy                                                         0          5,197,380                0.00               180,610.47
 WRIGHTSVILE POWER RE Energy                                                        0            118,533                0.00                 5,009.24
 YAZOO CITY RE Energy                                                               0                734                0.00                    32.46
 EXELON 150 1YR- CAP CHG                                                            0                  0                0.00               229,434.98
 JAP - DB ENERGY ENG CHG                                                            0                  0                0.00                    (0.04)
 JAP - EXELON ENG CHG                                                               0                  0                0.00                    (0.10)
 JAP - MEAM ENG CHG                                                                 0                  0                0.00                    (2.03)
 JAP - MLCI ENG CHG                                                                 0                  0                0.00                    (0.14)
 JAP - NRG ENG CHG                                                                  0                  0                0.00                    (0.14)
 JAP - SUEZ ENG CHG                                                                 0                  0                0.00                    (0.02)
 JAP - UNION ENG CHG                                                                0                  0                0.00                    (0.11)
 MERRILL LYNCH COMMODITIES ENG CHG ADJ - EXPENSE                                    0                  0                0.00                     0.13
 SWPP RESER - CAP CHG                                                               0                  0                0.00                   418.20
 SWPP TARIFF CHG                                                                    0                  0                0.00                   101.63
 UNION POWER PARTNERS LP ENG CHG ADJ - EXPENSE                                      0                  0                0.00                    (0.06)

 Subtotal Non-Associated Companies - Joint Account Purchases                        0        156,592,383                0.00             7,995,343.61


 Totals                                                                     33,576,796       384,500,300       5,466,653.72            18,494,264.11

 ESI Receivable from Entergy Mississippi, Inc.                                                                                         13,027,610.39




 Attachment Snapshot: 20100826181933                              RunID: 17029                                           Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                             9-212
                                                                                                                    Exhibit PJC-2
                                                                                                               2011 TX Rate Case
                                                                                                                    Page 51 of 70




 Entergy Electric System                        Date range - 20100701 through 20100731                                          Attachment 6-NO
 Intra-System Billing-201007RA                Company Summary - Entergy New Orleans, Inc.                                               Page 51



                                                                    Sales(KWH)          Purchases(KWH)    Revenue($)              Expense($)

 Purchases and Sales - Associated Companies

 Exchange Energy                                                         31,587,544          45,025,369       1,956,214.96              2,623,552.75
 Tele. AECC Excess Energy                                                         0           2,621,176               0.00                 86,371.53
 ARK.NU 1 - UPP from AR Desig. Energy                                             0          16,947,775               0.00                      0.00
 ARK.NU 2 - UPP from AR Desig. Energy                                             0          19,989,454               0.00                      0.00
 GGULF RET - UPP from AR Desig. Energy                                            0          13,799,542               0.00                      0.00
 GGULF RP - UPP from AR Desig. Energy                                             0           6,514,363               0.00                      0.00
 INDEPN 1 - UPP from AR Desig. Energy                                             0           4,846,579               0.00                      0.00
 RVRBND 1 - UPP from EGSL Desig. Energy                                           0          69,777,900               0.00                      0.00
 WH.BLF 1 - UPP from AR Desig. Energy                                             0           8,494,462               0.00                      0.00
 WH.BLF 2 - UPP from AR Desig. Energy                                             0           7,753,353               0.00                      0.00
 Equalized Res. Charge                                                            0                   0         466,393.86                      0.00
 Trans. Equal. Charge                                                             0                   0               0.00                703,783.04
 Fiber Optic Equalization                                                         0                   0               0.00                 18,451.16

 Subtotal Purchases and Sales - Associated Companies                     31,587,544         195,769,973       2,422,608.82              3,432,158.48



 Non-Associated Companies - Joint Account Sales                     Sales(KWH)          Purchases(KWH)    Revenue($)              Expense($)

 Net Balance for Sales                                                              0                0          (3,998.26)                        0.00
 Energy Supp. for Sales                                                       431,606                0          29,883.27                         0.00
 AIR LIQUIDE AMERICA - ANN FEE                                                      0                0             447.00                         0.00
 BASF CORPORATION - ANN FEE                                                         0                0             447.00                         0.00
 COTTONWOOD ENERGY CO - GEN REG                                                     0                0           1,049.04                         0.00
 CYPRES - GEN REG                                                                   0                0           1,810.88                         0.00
 DOW CHEMICAL - ANN FEE                                                             0                0             447.00                         0.00
 DUKE ENERGY HINDS - GEN REG                                                        0                0             784.05                         0.00
 DUKEENERGY HOTSPRING - GEN REG                                                     0                0           1,877.66                         0.00
 FORMOSA PLASTICS - ANN FEE                                                         0                0             447.00                         0.00
 GRAND RIVER DAM AUTHORITY ENG CHG ADJ - REVENUE                                    0                0              (0.01)                        0.00
 HUNTSMAN P.N. - ANN FEE                                                            0                0             447.00                         0.00
 KANSAS CITY POWER & LIGHT COMP ENG CHG ADJ - REVENUE                               0                0               0.01                         0.00
 MAGNET COVE - GEN REG                                                              0                0             371.63                         0.00
 MDEA CROSSROADS - GEN REG                                                          0                0             158.92                         0.00
 MISSOURI PUBLIC SERVICE ENG CHG ADJ - REVENUE                                      0                0               0.01                         0.00
 NEBRASKA PUBLIC POWER DISTRICT ENG CHG ADJ - REVENUE                               0                0              (0.01)                        0.00
 OCCIDENTAL CHEM CORP - GEN REG                                                     0                0             248.75                         0.00
 PINE BLUFF ENERGY - GEN REG                                                        0                0               0.11                         0.00
 PPG INDUSTR ES - ANN FEE                                                           0                0             447.00                         0.00
 SRW COGENERATION - GEN REG                                                         0                0             145.76                         0.00
 TENASKA FRONTIER - GEN REG                                                         0                0             700.69                         0.00
 UNION CARBIDE CORP - ANN FEE                                                       0                0             447.00                         0.00
 WRIGHTSVILE POWER - GEN REG                                                        0                0             950.84                         0.00
 YAZOO CITY - GEN REG                                                               0                0               0.53                         0.00

 Subtotal Non-Associated Companies - Joint Account Sales                      431,606                0          37,112.87                         0.00



 Non-Associated Companies - Joint Account Purchases                 Sales(KWH)          Purchases(KWH)    Revenue($)              Expense($)

 AECI RE Energy                                                                    0          3,094,753                0.00               132,065.67
 AEP SERVICE CORP. RE Energy                                                       0            171,760                0.00                 5,853.40
 AMEREN ENERGY NC. (AE) ACTING RE Energy                                           0            108,480                0.00                 5,315.53
 Ameren Energy Marketing Company RE Energy                                         0              2,260                0.00                    72.32
 BNP PARIBAS ENERGY TRADING GP RE Energy                                           0            183,015                0.00                 9,809.91
 CALP NE ENERGY SERVICES L.P. RE Energy                                            0            603,872                0.00                31,658.15
 CARGILL POWER MARKETS LLC RE Energy                                               0             75,710                0.00                 2,140.56
 CITIGROUP ENERGY NC RE Energy                                                     0             10,848                0.00                   364.09
 CLECO RE Energy                                                                   0            226,908                0.00                14,346.26
 CONSTELLATION ENERGY COMMODITIES GROUP INC RE Energy                              0            253,889                0.00                10,555.07
 COTTONWOOD ENERGY CO RE Energy                                                    0            169,522                0.00                 6,532.24
 CYPRES RE Energy                                                                  0              6,638                0.00                   274.46
 DB ENERGY TRAD NG LLC RE Energy                                                   0          4,674,492                0.00               238,724.80
 DUKE ENERGY HINDS RE Energy                                                       0             47,920                0.00                 1,821.89
 DUKEENERGY HOTSPRING RE Energy                                                    0             43,232                0.00                 1,609.44
 ENDURE ENERGY RE Energy                                                           0             64,413                0.00                 3,010.19
 ETEC RE Energy                                                                    0             52,882                0.00                 2,379.67
 EXELON GENERATION COMPANY LLC RE Energy                                           0          4,226,539                0.00               175,202.96
 J ARON & COMPANY RE Energy                                                        0          1,078,924                0.00                55,443.44
 Attachment Snapshot: 20100826181933                           RunID: 17029                                             Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                            9-213
                                                                                                                     Exhibit PJC-2
                                                                                                                2011 TX Rate Case
                                                                                                                     Page 52 of 70




 Entergy Electric System                           Date range - 20100701 through 20100731                                        Attachment 6-NO
 Intra-System Billing-201007RA                   Company Summary - Entergy New Orleans, Inc.                                             Page 52

                                                                       Sales(KWH)        Purchases(KWH)    Revenue($)              Expense($)

 J.P. MORGAN VENTURES ENERGY CORPORATION RE Energy                                  0            223,829                0.00                15,056.82
 JBO RE Energy                                                                      0            906,533                0.00                59,705.32
 KANSAS CITY POWER & LIGHT COMPANY RE Energy                                        0             65,133                0.00                 1,805.19
 MAGNET COVE RE Energy                                                              0            231,513                0.00                 8,481.26
 MDEA CROSSROADS RE Energy                                                          0              8,680                0.00                   368.22
 MERRILL LYNCH COMMODITIES INC RE Energy                                            0          8,771,914                0.00               431,852.92
 MORGAN STANLEY RE Energy                                                           0             11,118                0.00                   264.74
 NRG POWER MARKETING LLC. RE Energy                                                 0         10,079,323                0.00               487,837.23
 OCCIDENTAL POWER SERVICES RE Energy                                                0            257,550                0.00                16,318.15
 RAINBOW ENERGY MARKETING CORP RE Energy                                            0            629,363                0.00                20,213.51
 SMEPA RE Energy                                                                    0            135,600                0.00                12,104.24
 SOUTHERN COMPANY SERVICES INC. AS AGENT FO RE Energy                               0            503,980                0.00                62,272.05
 SUEZ Energy Marketing NA Inc. RE Energy                                            0          2,946,902                0.00               139,984.20
 TEA RE Energy                                                                      0             50,443                0.00                 1,478.40
 TENASKA FRONTIER RE Energy                                                         0             53,858                0.00                 2,029.38
 TENASKA RE Energy                                                                  0          1,148,074                0.00                68,987.77
 UNION POWER PARTNERS RE Energy                                                     0          7,454,707                0.00               374,211.01
 WESTAR ENERGY NC RE Energy                                                         0          1,685,241                0.00                58,562.31
 WRIGHTSVILE POWER RE Energy                                                        0             38,409                0.00                 1,623.20
 YAZOO CITY RE Energy                                                               0                237                0.00                    10.49
 EXELON 150 1YR- CAP CHG                                                            0                  0                0.00                74,393.55
 JAP - DB ENERGY ENG CHG                                                            0                  0                0.00                    (0.01)
 JAP - EXELON ENG CHG                                                               0                  0                0.00                    (0.03)
 JAP - MLCI ENG CHG                                                                 0                  0                0.00                    (0.04)
 JAP - NRG ENG CHG                                                                  0                  0                0.00                    (0.05)
 JAP - SUEZ ENG CHG                                                                 0                  0                0.00                    (0.01)
 JAP - UNION ENG CHG                                                                0                  0                0.00                    (0.04)
 MERRILL LYNCH COMMODITIES ENG CHG ADJ - EXPENSE                                    0                  0                0.00                     0.04
 SWPP RESER - CAP CHG                                                               0                  0                0.00                   135.60
 SWPP TARIFF CHG                                                                    0                  0                0.00                    32.95
 UNION POWER PARTNERS LP ENG CHG ADJ - EXPENSE                                      0                  0                0.00                    (0.02)

 Subtotal Non-Associated Companies - Joint Account Purchases                        0         50,298,464                0.00             2,534,908.40


 Totals                                                                     32,019,150       246,068,437       2,459,721.69              5,967,066.88

 ESI Receivable from Entergy New Orleans, Inc.                                                                                           3,507,345.19




 Attachment Snapshot: 20100826181933                              RunID: 17029                                           Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                             9-214
                                                                                                                Exhibit PJC-2
                                                                                                           2011 TX Rate Case
                                                                                                                Page 53 of 70




 Entergy Electric System                      Date range - 20100701 through 20100731                                      Attachment 6-EGSL
 Intra-System Billing-201007RA          Company Summary - Entergy Gulf States Louisiana, LLC                                        Page 53



                                                                  Sales(KWH)        Purchases(KWH)    Revenue($)              Expense($)

 Purchases and Sales - Associated Companies

 Exchange Energy                                                      388,628,993         8,681,301     23,688,200.69                 328,900.36
 Tele. AECC Excess Energy                                                       0        11,105,658              0.00                 365,958.24
 ACADIA POWER PARTNERS, LLC/WSPP B - UPP from LA Desig. Energy                  0        59,708,320              0.00                       0.00
 ARK.NU 1 - UPP from AR Desig. Energy                                           0        15,851,160              0.00                       0.00
 ARK.NU 2 - UPP from AR Desig. Energy                                           0        18,809,417              0.00                       0.00
 GGULF RET - UPP from AR Desig. Energy                                          0        11,616,357              0.00                       0.00
 GGULF RP - UPP from AR Desig. Energy                                           0         5,876,574              0.00                       0.00
 INDEPN 1 - UPP from AR Desig. Energy                                           0         4,526,010              0.00                       0.00
 LEWIS CREEK 1 - UPP from ETI Desig. Energy                                     0        58,217,025              0.00                       0.00
 LEWIS CREEK 2 - UPP from ETI Desig. Energy                                     0        65,725,375              0.00                       0.00
 PERVIL 1 - UPP from LA Desig. Energy                                           0       194,914,500              0.00                       0.00
 SABINE 1 - UPP from ETI Desig. Energy                                          0        51,146,250              0.00                       0.00
 SABINE 2 - UPP from ETI Desig. Energy                                          0        50,562,050              0.00                       0.00
 SABINE 3 - UPP from ETI Desig. Energy                                          0        80,097,500              0.00                       0.00
 SABINE 4 - UPP from ETI Desig. Energy                                          0        76,167,950              0.00                       0.00
 SABINE 5 - UPP from ETI Desig. Energy                                          0        70,933,725              0.00                       0.00
 WH.BLF 1 - UPP from AR Desig. Energy                                           0         8,331,086              0.00                       0.00
 WH.BLF 2 - UPP from AR Desig. Energy                                           0         7,011,078              0.00                       0.00
 CALCAS EU 1 Desig. Energy                                              4,690,725                 0              0.00                       0.00
 CALCAS EU 2 Desig. Energy                                              5,250,450                 0              0.00                       0.00
 NELSON 3 Desig. Energy                                                 5,192,225                 0              0.00                       0.00
 NELSON 4 Desig. Energy                                                62,280,775                 0              0.00                       0.00
 PERVIL 1 Desig. Energy                                                82,838,753                 0              0.00                       0.00
 RVRBND 1 Desig. Energy                                               416,923,129                 0              0.00                       0.00
 WILLOW GLEN 1 Desig. Energy                                            5,445,950                 0              0.00                       0.00
 WILLOW GLEN 2 Desig. Energy                                           10,391,250                 0              0.00                       0.00
 WILLOW GLEN 4 Desig. Energy                                           77,447,750                 0              0.00                       0.00
 Equalized Res. Charge                                                          0                 0              0.00                 136,245.95
 Trans. Equal. Charge                                                           0                 0              0.00                 742,024.61

 Subtotal Purchases and Sales - Associated Companies               1,059,090,000        799,281,336     23,688,200.69               1,573,129.16



 Non-Associated Companies - Joint Account Sales                   Sales(KWH)        Purchases(KWH)    Revenue($)              Expense($)

 Net Balance for Sales                                                          0                0         (16,932.22)                        0.00
 Energy Supp. for Sales                                                 1,912,208                0         130,511.51                         0.00
 AIR LIQUIDE AMERICA - ANN FEE                                                  0                0           1,893.00                         0.00
 BASF CORPORATION - ANN FEE                                                     0                0           1,893.00                         0.00
 CENTRAL LA ELEC CO ENG CHG ADJ - REVENUE                                       0                0              (0.01)                        0.00
 COTTONWOOD ENERGY CO - GEN REG                                                 0                0           4,442.59                         0.00
 CYPRES - GEN REG                                                               0                0           7,668.89                         0.00
 DOW CHEMICAL - ANN FEE                                                         0                0           1,893.00                         0.00
 DUKE ENERGY HINDS - GEN REG                                                    0                0           3,320.38                         0.00
 DUKEENERGY HOTSPRING - GEN REG                                                 0                0           7,951.70                         0.00
 FORMOSA PLASTICS - ANN FEE                                                     0                0           1,893.00                         0.00
 GRAND RIVER DAM AUTHORITY ENG CHG ADJ - REVENUE                                0                0              (0.05)                        0.00
 HUNTSMAN P.N. - ANN FEE                                                        0                0           1,893.00                         0.00
 KANSAS CITY POWER & LIGHT COMP ENG CHG ADJ - REVENUE                           0                0               0.03                         0.00
 MAGNET COVE - GEN REG                                                          0                0           1,573.82                         0.00
 MDEA CROSSROADS - GEN REG                                                      0                0             672.99                         0.00
 MISSOURI PUBLIC SERVICE ENG CHG ADJ - REVENUE                                  0                0               0.04                         0.00
 NEBRASKA PUBLIC POWER DISTRICT ENG CHG ADJ - REVENUE                           0                0              (0.05)                        0.00
 OCCIDENTAL CHEM CORP - GEN REG                                                 0                0           1,053.41                         0.00
 PINE BLUFF ENERGY - GEN REG                                                    0                0               0.47                         0.00
 PPG INDUSTR ES - ANN FEE                                                       0                0           1,893.00                         0.00
 SRW COGENERATION - GEN REG                                                     0                0             617.31                         0.00
 TENASKA FRONTIER - GEN REG                                                     0                0           2,967.35                         0.00
 UNION CARBIDE CORP - ANN FEE                                                   0                0           1,893.00                         0.00
 WRIGHTSVILE POWER - GEN REG                                                    0                0           4,026.72                         0.00
 YAZOO CITY - GEN REG                                                           0                0               2.25                         0.00

 Subtotal Non-Associated Companies - Joint Account Sales                1,912,208                0         161,128.13                         0.00



 Non-Associated Companies - Joint Account Purchases               Sales(KWH)        Purchases(KWH)    Revenue($)              Expense($)

 ACADIA POWER PARTNERS, LLC RE Energy                                          0                  0                0.00                    (0.01)
 AECI RE Energy                                                                0         13,111,621                0.00               559,525.81
 Attachment Snapshot: 20100826181933                         RunID: 17029                                           Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                        9-215
                                                                                                                  Exhibit PJC-2
                                                                                                             2011 TX Rate Case
                                                                                                                  Page 54 of 70




 Entergy Electric System                       Date range - 20100701 through 20100731                                       Attachment 6-EGSL
 Intra-System Billing-201007RA           Company Summary - Entergy Gulf States Louisiana, LLC                                         Page 54

                                                                    Sales(KWH)       Purchases(KWH)     Revenue($)              Expense($)

 AEP SERVICE CORP. RE Energy                                                     0           727,700                 0.00                24,799.18
 AMEREN ENERGY NC. (AE) ACTING RE Energy                                         0           459,600                 0.00                22,520.40
 Ameren Energy Marketing Company RE Energy                                       0             9,575                 0.00                   306.40
 BNP PARIBAS ENERGY TRADING GP RE Energy                                         0           775,383                 0.00                41,562.12
 CALP NE A BASE IN RE Energy                                                     0       137,098,200                 0.00             4,886,179.84
 CALP NE B BASE IN RE Energy                                                     0        98,223,400                 0.00             3,779,830.92
 CALP NE C BASE IN RE Energy                                                     0         5,787,100                 0.00               275,641.39
 CALP NE B RAMP IN RE Energy                                                     0         1,973,300                 0.00                75,957.00
 CALP NE C RAMP IN RE Energy                                                     0            34,100                 0.00                 1,317.79
 CALP NE ENERGY SERVICES L.P. RE Energy                                          0         2,558,432                 0.00               134,126.16
 CALP NE EXCESS N RE Energy                                                      0           422,000                 0.00                14,994.68
 CARGILL POWER MARKETS LLC RE Energy                                             0           320,760                 0.00                 9,068.87
 CITIGROUP ENERGY NC RE Energy                                                   0            45,959                 0.00                 1,542.49
 CLECO RE Energy                                                                 0           961,242                 0.00                60,771.75
 CONOCOPH LLIPS COMPANY RE Energy                                                0         1,969,375                 0.00               117,903.00
 CONSTELLATION ENERGY COMMODITIES GROUP INC RE Energy                            0         1,075,654                 0.00                44,718.46
 COTTONWOOD ENERGY CO RE Energy                                                  0           718,363                 0.00                27,680.48
 CYPRES RE Energy                                                                0            28,106                 0.00                 1,162.40
 DB ENERGY TRAD NG LLC RE Energy                                                 0        19,804,486                 0.00             1,011,410.14
 DOW P PELINE COMPANY RE Energy                                                  0         2,127,500                 0.00               132,892.87
 DUKE ENERGY HINDS RE Energy                                                     0           203,359                 0.00                 7,732.15
 DUKEENERGY HOTSPRING RE Energy                                                  0           183,255                 0.00                 6,821.62
 ENDURE ENERGY RE Energy                                                         0           272,879                 0.00                12,752.13
 ETEC RE Energy                                                                  0           224,050                 0.00                10,082.27
 EXELON GENERATION COMPANY LLC RE Energy                                         0        17,906,524                 0.00               742,280.74
 J ARON & COMPANY RE Energy                                                      0         4,571,051                 0.00               234,897.47
 J.P. MORGAN VENTURES ENERGY CORPORATION RE Energy                               0           948,303                 0.00                63,791.79
 JBO RE Energy                                                                   0         3,840,670                 0.00               252,951.97
 KANSAS CITY POWER & LIGHT COMPANY RE Energy                                     0           275,952                 0.00                 7,648.14
 MAGNET COVE RE Energy                                                           0           980,951                 0.00                35,935.90
 MDEA CROSSROADS RE Energy                                                       0            36,766                 0.00                 1,560.00
 MERRILL LYNCH COMMODITIES INC RE Energy                                         0        37,164,138                 0.00             1,829,640.85
 MORGAN STANLEY RE Energy                                                        0            47,110                 0.00                 1,121.82
 NRG POWER MARKETING LLC. RE Energy                                              0        42,703,074                 0.00             2,066,821.42
 OCCIDENTAL POWER SERVICES RE Energy                                             0         1,091,166                 0.00                69,135.39
 RAINBOW ENERGY MARKETING CORP RE Energy                                         0         2,666,424                 0.00                85,638.22
 SMEPA RE Energy                                                                 0           574,496                 0.00                51,281.84
 SOUTHERN COMPANY SERVICES INC. AS AGENT FO RE Energy                            0         2,135,225                 0.00               263,829.55
 SUEZ Energy Marketing NA Inc. RE Energy                                         0        12,485,194                 0.00               593,072.66
 TEA RE Energy                                                                   0           213,711                 0.00                 6,263.48
 TENASKA FRONTIER RE Energy                                                      0           228,269                 0.00                 8,601.20
 TENASKA RE Energy                                                               0         4,864,077                 0.00               292,282.06
 UNION POWER PARTNERS RE Energy                                                  0        31,583,431                 0.00             1,585,423.12
 WESTAR ENERGY NC RE Energy                                                      0         7,139,870                 0.00               248,112.40
 WRIGHTSVILE POWER RE Energy                                                     0           162,823                 0.00                 6,880.95
 YAZOO CITY RE Energy                                                            0             1,011                 0.00                    44.72
 CALP NE-CARVILLE - STARTUP CHG - 0                                              0                 0                 0.00               196,850.41
 CARVILLE - 485 MW - CAP CHG                                                     0                 0                 0.00             2,430,000.00
 CONOCO PHIL PS - 100 MW - CAP CHG                                               0                 0                 0.00                94,875.00
 DOW - 100 MW - CAP CHG                                                          0                 0                 0.00                86,250.00
 DOW P PELINE COMPANY ENG CHG ADJ - EXPENSE                                      0                 0                 0.00                     0.29
 EXELON 150 1YR- CAP CHG                                                         0                 0                 0.00               315,185.06
 JAP - ACADIA ADJ ENG CHG                                                        0                 0                 0.00                     0.01
 JAP - CONOCO ENG CHG                                                            0                 0                 0.00                    (0.05)
 JAP - DB ENERGY ENG CHG                                                         0                 0                 0.00                    (0.06)
 JAP - EXELON ENG CHG                                                            0                 0                 0.00                    (0.14)
 JAP - MLCI ENG CHG                                                              0                 0                 0.00                    (0.19)
 JAP - NRG ENG CHG                                                               0                 0                 0.00                    (0.20)
 JAP - SUEZ ENG CHG                                                              0                 0                 0.00                    (0.03)
 JAP - UNION ENG CHG                                                             0                 0                 0.00                    (0.15)
 MERRILL LYNCH COMMODITIES ENG CHG ADJ - EXPENSE                                 0                 0                 0.00                     0.18
 SWPP RESER - CAP CHG                                                            0                 0                 0.00                   574.50
 SWPP TARIFF CHG                                                                 0                 0                 0.00                   139.61
 UNION POWER PARTNERS LP ENG CHG ADJ - EXPENSE                                   0                 0                 0.00                    (0.09)

 Subtotal Non-Associated Companies - Joint Account Purchases                     0       460,735,635                 0.00           22,832,390.15


 Totals                                                              1,061,002,208      1,260,016,971     23,849,328.82             24,405,519.31

 ESI Receivable from Entergy Gulf States Louisiana, LLC                                                                                 556,190.49




 Attachment Snapshot: 20100826181933                           RunID: 17029                                           Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                          9-216
                                                                                                                   Exhibit PJC-2
                                                                                                              2011 TX Rate Case
                                                                                                                   Page 55 of 70




 Entergy Electric System                          Date range - 20100701 through 20100731                                       Attachment 6-ETI
 Intra-System Billing-201007RA                    Company Summary - Entergy Texas, Inc                                                 Page 55



                                                                     Sales(KWH)        Purchases(KWH)    Revenue($)              Expense($)

 Purchases and Sales - Associated Companies

 Exchange Energy                                                           2,259,218       328,392,353        181,081.08             19,143,734.58
 Tele. AECC Excess Energy                                                          0         9,487,663              0.00                312,641.59
 ARK.NU 1 - UPP from AR Desig. Energy                                              0        16,654,966              0.00                      0.00
 ARK.NU 2 - UPP from AR Desig. Energy                                              0        19,768,134              0.00                      0.00
 CALCAS EU 1 - UPP from EGSL Desig. Energy                                         0         4,690,725              0.00                      0.00
 CALCAS EU 2 - UPP from EGSL Desig. Energy                                         0         5,250,450              0.00                      0.00
 GGULF RET - UPP from AR Desig. Energy                                             0        12,205,279              0.00                      0.00
 GGULF RP - UPP from AR Desig. Energy                                              0         6,173,783              0.00                      0.00
 INDEPN 1 - UPP from AR Desig. Energy                                              0         4,757,472              0.00                      0.00
 NELSON 3 - UPP from EGSL Desig. Energy                                            0         5,192,225              0.00                      0.00
 NELSON 4 - UPP from EGSL Desig. Energy                                            0        62,280,775              0.00                      0.00
 PERVIL 1 - UPP from EGSL Desig. Energy                                            0        82,838,753              0.00                      0.00
 RVRBND 1 - UPP from EGSL Desig. Energy                                            0       207,589,429              0.00                      0.00
 WH.BLF 1 - UPP from AR Desig. Energy                                              0         8,755,797              0.00                      0.00
 WH.BLF 2 - UPP from AR Desig. Energy                                              0         7,368,498              0.00                      0.00
 WILLOW GLEN 1 - UPP from EGSL Desig. Energy                                       0         5,445,950              0.00                      0.00
 WILLOW GLEN 2 - UPP from EGSL Desig. Energy                                       0        10,391,250              0.00                      0.00
 WILLOW GLEN 4 - UPP from EGSL Desig. Energy                                       0        77,447,750              0.00                      0.00
 LEWIS CREEK 1 Desig. Energy                                              58,217,025                 0              0.00                      0.00
 LEWIS CREEK 2 Desig. Energy                                              65,725,375                 0              0.00                      0.00
 SABINE 1 Desig. Energy                                                   51,146,250                 0              0.00                      0.00
 SABINE 2 Desig. Energy                                                   50,562,050                 0              0.00                      0.00
 SABINE 3 Desig. Energy                                                   80,097,500                 0              0.00                      0.00
 SABINE 4 Desig. Energy                                                   76,167,950                 0              0.00                      0.00
 SABINE 5 Desig. Energy                                                   70,933,725                 0              0.00                      0.00
 Equalized Res. Charge                                                             0                 0              0.00              2,155,389.66
 Trans. Equal. Charge                                                              0                 0              0.00               (246,255.30)

 Subtotal Purchases and Sales - Associated Companies                     455,109,093       874,691,252        181,081.08             21,365,510.53



 Non-Associated Companies - Joint Account Sales                      Sales(KWH)        Purchases(KWH)    Revenue($)              Expense($)

 Net Balance for Sales                                                             0                0         (14,821.28)                        0.00
 Energy Supp. for Sales                                                    1,590,958                0         109,695.70                         0.00
 AIR LIQUIDE AMERICA - ANN FEE                                                     0                0           1,657.00                         0.00
 BASF CORPORATION - ANN FEE                                                        0                0           1,657.00                         0.00
 CENTRAL LA ELEC CO ENG CHG ADJ - REVENUE                                          0                0              (0.01)                        0.00
 COTTONWOOD ENERGY CO - GEN REG                                                    0                0           3,888.73                         0.00
 CYPRES - GEN REG                                                                  0                0           6,712.81                         0.00
 DOW CHEMICAL - ANN FEE                                                            0                0           1,657.00                         0.00
 DUKE ENERGY HINDS - GEN REG                                                       0                0           2,906.42                         0.00
 DUKEENERGY HOTSPRING - GEN REG                                                    0                0           6,960.36                         0.00
 FORMOSA PLASTICS - ANN FEE                                                        0                0           1,657.00                         0.00
 GRAND RIVER DAM AUTHORITY ENG CHG ADJ - REVENUE                                   0                0              (0.04)                        0.00
 HUNTSMAN P.N. - ANN FEE                                                           0                0           1,657.00                         0.00
 KANSAS CITY POWER & LIGHT COMP ENG CHG ADJ - REVENUE                              0                0               0.03                         0.00
 MAGNET COVE - GEN REG                                                             0                0           1,377.61                         0.00
 MDEA CROSSROADS - GEN REG                                                         0                0             589.09                         0.00
 MISSOURI PUBLIC SERVICE ENG CHG ADJ - REVENUE                                     0                0               0.03                         0.00
 NEBRASKA PUBLIC POWER DISTRICT ENG CHG ADJ - REVENUE                              0                0              (0.04)                        0.00
 OCCIDENTAL CHEM CORP - GEN REG                                                    0                0             922.08                         0.00
 PINE BLUFF ENERGY - GEN REG                                                       0                0               0.41                         0.00
 PPG INDUSTR ES - ANN FEE                                                          0                0           1,657.00                         0.00
 SRW COGENERATION - GEN REG                                                        0                0             540.35                         0.00
 TENASKA FRONTIER - GEN REG                                                        0                0           2,597.42                         0.00
 UNION CARBIDE CORP - ANN FEE                                                      0                0           1,657.00                         0.00
 WRIGHTSVILE POWER - GEN REG                                                       0                0           3,524.71                         0.00
 YAZOO CITY - GEN REG                                                              0                0               1.97                         0.00

 Subtotal Non-Associated Companies - Joint Account Sales                   1,590,958                0         136,495.35                         0.00



 Non-Associated Companies - Joint Account Purchases                  Sales(KWH)        Purchases(KWH)    Revenue($)              Expense($)

 AECI RE Energy                                                                   0         11,201,365                0.00               478,007.57
 AEP SERVICE CORP. RE Energy                                                      0            621,680                0.00                21,186.20
 AMEREN ENERGY NC. (AE) ACTING RE Energy                                          0            392,640                0.00                19,239.34
 Ameren Energy Marketing Company RE Energy                                        0              8,180                0.00                   261.76
 Attachment Snapshot: 20100826181933                            RunID: 17029                                           Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                           9-217
                                                                                                                   Exhibit PJC-2
                                                                                                              2011 TX Rate Case
                                                                                                                   Page 56 of 70




 Entergy Electric System                        Date range - 20100701 through 20100731                                         Attachment 6-ETI
 Intra-System Billing-201007RA                  Company Summary - Entergy Texas, Inc                                                   Page 56

                                                                    Sales(KWH)        Purchases(KWH)     Revenue($)              Expense($)

 BNP PARIBAS ENERGY TRADING GP RE Energy                                         0            662,416                 0.00                35,506.97
 CALP NE ENERGY SERVICES L.P. RE Energy                                          0          2,185,696                 0.00               114,585.23
 CARGILL POWER MARKETS LLC RE Energy                                             0            274,031                 0.00                 7,747.73
 CITIGROUP ENERGY NC RE Energy                                                   0             39,264                 0.00                 1,317.80
 CLECO RE Energy                                                                 0            821,270                 0.00                51,922.59
 CONOCOPH LLIPS COMPANY RE Energy                                                0          1,575,625                 0.00                94,510.83
 CONSTELLATION ENERGY COMMODITIES GROUP INC RE Energy                            0            918,941                 0.00                38,203.61
 COTTONWOOD ENERGY CO RE Energy                                                  0            613,669                 0.00                23,646.38
 CYPRES RE Energy                                                                0             24,013                 0.00                   993.07
 DB ENERGY TRAD NG LLC RE Energy                                                 0         16,919,189                 0.00               864,058.62
 DOW P PELINE COMPANY RE Energy                                                  0          1,572,500                 0.00                98,225.13
 DUKE ENERGY HINDS RE Energy                                                     0            173,693                 0.00                 6,603.99
 DUKEENERGY HOTSPRING RE Energy                                                  0            156,582                 0.00                 5,828.80
 ENDURE ENERGY RE Energy                                                         0            233,125                 0.00                10,894.33
 ETEC EXCESS-HRSNHRDN RE Energy                                                  0              4,937                 0.00                   176.69
 ETEC RE Energy                                                                  0            191,412                 0.00                 8,613.51
 EXELON FRONT ER 10YR RE Energy                                                  0         93,424,000                 0.00             3,266,581.59
 EXELON GENERATION COMPANY LLC RE Energy                                         0         15,297,742                 0.00               634,138.34
 HARDIN RE Energy                                                                0          9,029,000                 0.00               488,396.52
 J ARON & COMPANY RE Energy                                                      0          3,905,132                 0.00               200,676.84
 J.P. MORGAN VENTURES ENERGY CORPORATION RE Energy                               0            810,147                 0.00                54,498.11
 JBO RE Energy                                                                   0          3,281,160                 0.00               216,101.01
 KANSAS CITY POWER & LIGHT COMPANY RE Energy                                     0            235,748                 0.00                 6,533.86
 MAGNET COVE RE Energy                                                           0            838,011                 0.00                30,699.64
 MDEA CROSSROADS RE Energy                                                       0             31,413                 0.00                 1,332.85
 MERRILL LYNCH COMMODITIES INC RE Energy                                         0         31,749,681                 0.00             1,563,079.13
 MORGAN STANLEY RE Energy                                                        0             40,246                 0.00                   958.37
 NRG POWER MARKETING LLC. RE Energy                                              0         36,481,830                 0.00             1,765,715.06
 OCCIDENTAL POWER SERVICES RE Energy                                             0            932,192                 0.00                59,062.49
 RAINBOW ENERGY MARKETING CORP RE Energy                                         0          2,277,962                 0.00                73,162.10
 SAN JACINTO 1 RE Energy                                                         0          5,722,000                 0.00               353,399.75
 SAN JACINTO 2 RE Energy                                                         0          5,612,000                 0.00               346,601.58
 SMEPA RE Energy                                                                 0            490,800                 0.00                43,810.72
 SOUTHERN COMPANY SERVICES INC. AS AGENT FO RE Energy                            0          1,824,140                 0.00               225,391.64
 SUEZ Energy Marketing NA Inc. RE Energy                                         0         10,666,236                 0.00               506,668.80
 TEA RE Energy                                                                   0            182,578                 0.00                 5,351.05
 TENASKA FRONTIER RE Energy                                                      0            194,958                 0.00                 7,346.06
 TENASKA RE Energy                                                               0          4,155,437                 0.00               249,700.11
 UNION POWER PARTNERS RE Energy                                                  0         26,982,052                 0.00             1,354,443.71
 WESTAR ENERGY NC RE Energy                                                      0          6,099,672                 0.00               211,965.28
 WRIGHTSVILE POWER RE Energy                                                     0            139,079                 0.00                 5,877.43
 YAZOO CITY RE Energy                                                            0                863                 0.00                    38.17
 CONOCO PHIL PS - 100 MW - CAP CHG                                               0                  0                 0.00                70,125.00
 DOW - 100 MW - CAP CHG                                                          0                  0                 0.00                63,750.00
 DOW P PELINE COMPANY ENG CHG ADJ - EXPENSE                                      0                  0                 0.00                     0.21
 ETEC - STARTUP CHG - 0                                                          0                  0                 0.00                46,121.40
 ETEC - STARTUP CHG - 1                                                          0                  0                 0.00                39,203.19
 ETEC SAN JAC- 146 MW - CAP CHG                                                  0                  0                 0.00               985,500.00
 EXELON 150 10YR- CAP CHG                                                        0                  0                 0.00             1,527,900.00
 EXELON 150 1YR- CAP CHG                                                         0                  0                 0.00               269,265.15
 EXELON GENERATION COMPANY LLC - STARTUP CHG - 0                                 0                  0                 0.00                70,880.00
 JAP - CONOCO ENG CHG                                                            0                  0                 0.00                    (0.03)
 JAP - DB ENERGY ENG CHG                                                         0                  0                 0.00                    (0.05)
 JAP - EXELON ENG CHG                                                            0                  0                 0.00                    (0.12)
 JAP - HARDIN ENG CHG                                                            0                  0                 0.00                     0.01
 JAP - MLCI ENG CHG                                                              0                  0                 0.00                    (0.16)
 JAP - NRG ENG CHG                                                               0                  0                 0.00                    (0.17)
 JAP - SAN JAC ENG CHG                                                           0                  0                 0.00                     0.05
 JAP - SUEZ ENG CHG                                                              0                  0                 0.00                    (0.03)
 JAP - UNION ENG CHG                                                             0                  0                 0.00                    (0.13)
 MERRILL LYNCH COMMODITIES ENG CHG ADJ - EXPENSE                                 0                  0                 0.00                     0.16
 SWPP RESER - CAP CHG                                                            0                  0                 0.00                   490.80
 SWPP TARIFF CHG                                                                 0                  0                 0.00                   119.27
 UNION POWER PARTNERS LP ENG CHG ADJ - EXPENSE                                   0                  0                 0.00                    (0.07)

 Subtotal Non-Associated Companies - Joint Account Purchases                     0        298,994,307                 0.00           16,626,414.84


 Totals                                                                 456,700,051      1,173,685,559        317,576.43             37,991,925.37

 ESI Receivable from Entergy Texas, Inc                                                                                              37,674,348.94




 Attachment Snapshot: 20100826181933                           RunID: 17029                                            Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                           9-218
                                                                                                     Exhibit PJC-2
                                                                                                2011 TX Rate Case
                                                                                                     Page 57 of 70




 Entergy Electric System                               Date range - 20100701 through 20100731             Attachment 6-System
 Intra-System Billing-201007RA                                    System Summary                                      Page 57



                   Net Receivable from Entergy Arkansas, Inc.                                      18,197,161.09
                   Net Receivable from Entergy Louisiana, LLC                                      24,051,214.36
                   Net Receivable from Entergy Mississippi, Inc.                                   13,027,610.39
                   Net Receivable from Entergy New Orleans, Inc.                                    3,507,345.19
                   Net Receivable from Entergy Gulf States Louisiana, LLC                             556,190.49
                   Net Receivable from Entergy Texas, Inc                                          37,674,348.94

                   Net Receivable from System Companies                                            97,013,870.46


                   Net Payable to Outside Companies                                                (97,013,870.46)




 Attachment Snapshot: 20100826181933                                        RunID: 17029                Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                              9-219
                                                                                                                    Exhibit PJC-2
                                                                                                               2011 TX Rate Case
                                                                                                                    Page 58 of 70




 Entergy Electric System                                Date range - 20100701 through 20100731                                    Attachment 11
 Intra-System Billing-201007RA                       Joint Account / Individual Company Purchases                                       Page 58



                                       Description                      KWH           Mills per KWH        Charge

                                       ACADIA POWER PARTNERS, LLC/WSPP B
                                          LA                    179,125,000                34 0933    6,106,961.20
                                          Total                 179,125,000                34.0933    6,106,961.20

                                       AECI/WSPP A
                                           AR                        499,659               28 6147      14,297.61
                                           LA                        601,840               28 6147      17,221.49
                                           MS                        333,584               28 6147       9,545.41
                                           NO                        108,163               28 6147       3,095 05
                                           EGSL                      458,259               28 6147      13,112.93
                                           ETI                       391,495               28 6147      11,202.51
                                           Total                   2,393,000               28.6147      68,475.00

                                       AECI/WSPP B
                                           AR                      4,176,000               38 0000     158,688 00
                                           LA                      5,030,000               38 0000     191,140 00
                                           MS                      2,788,000               38 0000     105,944 00
                                           NO                        904,000               38 0000      34,352.00
                                           EGSL                    3,830,000               38 0000     145,540 00
                                           ETI                     3,272,000               38 0000     124,336 00
                                           Total                  20,000,000               38.0000     760,000.00

                                       AECI/WSPP C SYSTEM FIRM
                                           AR                      9,620,460               45.4331      437,087 56
                                           LA                     11,587,863               45.4331      526,472 93
                                           MS                      6,422,855               45.4331      291,810 20
                                           NO                      2,082,590               45.4331       94,618.62
                                           EGSL                    8,823,362               45.4331      400,872 88
                                           ETI                     7,537,870               45.4331      342,469 06
                                           Total                  46,075,000               45.4331    2,093,331.25

                                       AEP SERVICE CORP./WSPP A
                                           AR                        626,400               30.1000      18,854.63
                                           LA                        754,500               30.1000      22,710.45
                                           MS                        418,200               30.1000      12,587.82
                                           NO                        135,600               30.1000       4,081 56
                                           EGSL                      574,500               30.1000      17,292.46
                                           ETI                       490,800               30.1000      14,773.08
                                           Total                   3,000,000               30.1000      90,300.00

                                       AEP SERVICE CORP./WSPP C
                                           AR                        167,040               49 0000       8,184 96
                                           LA                        201,200               49 0000       9,858 88
                                           MS                        111,520               49 0000       5,464.48
                                           NO                         36,160               49 0000       1,771 84
                                           EGSL                      153,200               49 0000       7,506.72
                                           ETI                       130,880               49 0000       6,413.12
                                           Total                     800,000               49.0000      39,200.00

                                       AMEREN ENERGY INC. (AE) ACTING /WSPP C SYSTEM FIRM
                                          AR                         501,120             49 0000        24,554.89
                                          LA                         603,600             49 0000        29,576.40
                                          MS                         334,560             49 0000        16,393.44
                                          NO                         108,480             49 0000         5,315 53
                                          EGSL                       459,600             49 0000        22,520.40
                                          ETI                        392,640             49 0000        19,239.34
                                          Total                    2,400,000             49.0000       117,600.00

                                       AMEREN ENERGY MARKETING COMPANY/WSPP A
                                          AR                      10,440                   32 0000          334 08
                                          LA                      12,575                   32 0000          402.40
                                          MS                       6,970                   32 0000          223 04
                                          NO                       2,260                   32 0000           72.32
                                          EGSL                     9,575                   32 0000          306.40
                                          ETI                      8,180                   32 0000          261.76
                                          Total                   50,000                   32.0000        1,600.00

                                       BNP PAR BAS ENERGY TRAD NG GP/WSPP A
                                           AR                       41,760                 35 5000        1,482.48
                                           LA                       50,300                 35 5000        1,785 65
                                           MS                       27,880                 35 5000          989.74
                                           NO                        9,040                 35 5000          320 92
                                           EGSL                     38,300                 35 5000        1,359 65
 Attachment Snapshot: 20100826181933                                   RunID: 17029                                   Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                            9-220
                                                                                                                    Exhibit PJC-2
                                                                                                               2011 TX Rate Case
                                                                                                                    Page 59 of 70




 Entergy Electric System                                 Date range - 20100701 through 20100731                                   Attachment 11
 Intra-System Billing-201007RA                        Joint Account / Individual Company Purchases                                      Page 59

                                       Description                      KWH           Mills per KWH        Charge

                                           ETI                        32,720               35 5000        1,161 56
                                           Total                     200,000               35.5000        7,100.00

                                       BNP PAR BAS ENERGY TRAD NG GP/WSPP B
                                           AR                       803,671                54 5427      43,834.51
                                           LA                       968,024                54 5427      52,798.73
                                           MS                       536,551                54 5427      29,264.89
                                           NO                       173,975                54 5427       9,488 99
                                           EGSL                     737,083                54 5427      40,202.47
                                           ETI                      629,696                54 5427      34,345.41
                                           Total                  3,849,000                54.5427     209,935.00

                                       BURAS TEMP
                                          LA                         131,908              260 5153      34,364.05
                                          Total                      131,908              260.5153      34,364.05

                                       CALPINE A BASE   N
                                           EGSL                   137,098,200              35 6400    4,886,179.84
                                           Total                  137,098,200              35.6400    4,886,179.84

                                       CALPINE B BASE   N
                                           EGSL                    98,223,400              38.4820    3,779,830.92
                                           Total                   98,223,400              38.4820    3,779,830.92

                                       CALPINE C BASE IN
                                           EGSL                     5,787,100              47 6303     275,641 39
                                           Total                    5,787,100              47.6303     275,641.39

                                       CALPINE B RAMP IN
                                           EGSL                     1,973,300              38.4924      75,957.00
                                           Total                    1,973,300              38.4924      75,957.00

                                       CALPINE C RAMP IN
                                           EGSL                       34,100               38 6449        1,317.79
                                           Total                      34,100               38.6449        1,317.79

                                       CALPINE ENERGY SERVICES L P /WSPP B
                                           AR                      2,789,568               52.4251     146,243 56
                                           LA                      3,360,048               52.4251     176,151 06
                                           MS                      1,862,384               52.4251      97,635.84
                                           NO                        603,872               52.4251      31,658.15
                                           EGSL                    2,558,432               52.4251     134,126.16
                                           ETI                     2,185,696               52.4251     114,585 23
                                           Total                  13,360,000               52.4251     700,400.00

                                       CALPINE EXCESS IN
                                           EGSL                      422,000               35 5324      14,994.68
                                           Total                     422,000               35.5324      14,994.68

                                       CARGILL POWER MARKETS LLC/WSPP A
                                          AR                       349,740                 28 2731       9,888 24
                                          LA                       421,265                 28 2731      11,910.49
                                          MS                       233,494                 28 2731       6,601 61
                                          NO                        75,710                 28 2731       2,140 56
                                          EGSL                     320,760                 28 2731       9,068 87
                                          ETI                      274,031                 28 2731       7,747.73
                                          Total                  1,675,000                 28.2731      47,357.50

                                       CITIGROUP ENERGY INC/WSPP A
                                            AR                      50,112                 33 5625        1,681 88
                                            LA                      60,361                 33 5625        2,025 87
                                            MS                      33,456                 33 5625        1,122 87
                                            NO                      10,848                 33 5625          364 09
                                            EGSL                    45,959                 33 5625        1,542.49
                                            ETI                     39,264                 33 5625        1,317 80
                                            Total                  240,000                 33.5625        8,055.00

                                       CLECO/WSPP B
                                           AR                       1,048,172              63 2225      66,267.70
                                           LA                       1,262,618              63 2225      79,826.20
                                           MS                         699,790              63 2225      44,242.50
                                           NO                         226,908              63 2225      14,346.26
                                           EGSL                       961,242              63 2225      60,771.75
                                           ETI                        821,270              63 2225      51,922.59
                                           Total                    5,020,000              63.2225     317,377.00
 Attachment Snapshot: 20100826181933                                   RunID: 17029                                   Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                            9-221
                                                                                                                  Exhibit PJC-2
                                                                                                             2011 TX Rate Case
                                                                                                                  Page 60 of 70




 Entergy Electric System                                 Date range - 20100701 through 20100731                                 Attachment 11
 Intra-System Billing-201007RA                        Joint Account / Individual Company Purchases                                    Page 60

                                       Description                      KWH           Mills per KWH      Charge


                                       CONOCOPHILLIPS COMPANY / NTRA-DAY CALL OPTION
                                          EGSL                    1,969,375                59 9193    117,903 00
                                          ETI                     1,575,625                59 9193     94,510.83
                                          Total                   3,545,000                59.9193    212,413.83

                                       CONSTELLATION ENERGY COMMODITIES GROUP INC/WSPP A
                                          AR                      37,584             30.7500            1,155.70
                                          LA                      45,271             30.7500            1,392 08
                                          MS                      25,092             30.7500              771 58
                                          NO                       8,136             30.7500              250.19
                                          EGSL                    34,469             30.7500            1,059 92
                                          ETI                     29,448             30.7500              905 53
                                          Total                  180,000             30.7500            5,535.00

                                       CONSTELLATION ENERGY COMMODITIES GROUP INC/WSPP C
                                          AR                    1,135,245            41 9319           47,602.94
                                          LA                    1,367,406            41 9319           57,338.15
                                          MS                      757,918            41 9319           31,780.91
                                          NO                      245,753            41 9319           10,304.88
                                          EGSL                  1,041,185            41 9319           43,658.54
                                          ETI                     889,493            41 9319           37,298.08
                                          Total                 5,437,000            41.9319          227,983.50

                                       COTTONWOOD ENERGY CO/EXS50
                                          AR                      41,619                   20 8668        868.44
                                          LA                      50,135                   20 8668      1,046.16
                                          MS                      27,787                   20 8668        579 81
                                          NO                       9,005                   20 8668        187 93
                                          EGSL                    38,172                   20 8668        796 52
                                          ETI                     32,612                   20 8668        680 51
                                          Total                  199,330                   20.8668      4,159.37

                                       COTTONWOOD ENERGY CO/EXS75
                                          AR                      10,037                   30.4381        305.49
                                          LA                      12,102                   30.4381        368 39
                                          MS                       6,703                   30.4381        204 00
                                          NO                       2,169                   30.4381         65.99
                                          EGSL                     9,218                   30.4381        280 59
                                          ETI                      7,868                   30.4381        239 52
                                          Total                   48,097                   30.4381      1,463.98

                                       COTTONWOOD ENERGY CO/EXS90
                                          AR                     438,669                   40 3917     17,718.60
                                          LA                     528,321                   40 3917     21,339.80
                                          MS                     292,830                   40 3917     11,828.07
                                          NO                      94,934                   40 3917      3,834 55
                                          EGSL                   402,325                   40 3917     16,250.50
                                          ETI                    343,686                   40 3917     13,882.01
                                          Total                2,100,765                   40.3917     84,853.53

                                       COTTONWOOD ENERGY CO/EXSSS50
                                          AR                      2,541                    18 5781        47.21
                                          LA                      3,060                    18 5781        56.85
                                          MS                      1,696                    18 5781        31.51
                                          NO                        550                    18 5781        10.22
                                          EGSL                    2,330                    18 5781        43.28
                                          ETI                     1,990                    18 5781        36.97
                                          Total                  12,167                    18.5781       226.04

                                       COTTONWOOD ENERGY CO/EXSSTSH
                                          AR                     290,367                   38.7115     11,240.56
                                          LA                     349,743                   38.7115     13,539.10
                                          MS                     193,858                   38.7115      7,504 52
                                          NO                      62,864                   38.7115      2,433 55
                                          EGSL                   266,318                   38.7115     10,309.59
                                          ETI                    227,513                   38.7115      8,807 37
                                          Total                1,390,663                   38.7115     53,834.69

                                       CYPRES/EXS50
                                          AR                           3,999               25 0501       100.18
                                          LA                           4,816               25 0501       120 64
                                          MS                           2,669               25 0501        66.86
                                          NO                             866               25 0501        21.69
                                          EGSL                         3,667               25 0501        91.86
 Attachment Snapshot: 20100826181933                                   RunID: 17029                                 Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                          9-222
                                                                                                                    Exhibit PJC-2
                                                                                                               2011 TX Rate Case
                                                                                                                    Page 61 of 70




 Entergy Electric System                                 Date range - 20100701 through 20100731                                   Attachment 11
 Intra-System Billing-201007RA                        Joint Account / Individual Company Purchases                                      Page 61

                                       Description                      KWH           Mills per KWH        Charge

                                           ETI                         3,133               25 0501          78.48
                                           Total                      19,150               25.0501         479.71

                                       CYPRES/EXS75
                                          AR                             219               37 5714           8 23
                                          LA                             264               37 5714           9 92
                                          MS                             146               37 5714           5.48
                                          NO                              48               37 5714           1 80
                                          EGSL                           201               37 5714           7 56
                                          ETI                            172               37 5714           6.46
                                          Total                        1,050               37.5714          39.45

                                       CYPRES/EXS90
                                          AR                          26,430               43 8542        1,159 09
                                          LA                          31,833               43 8542        1,396 00
                                          MS                          17,648               43 8542          773 94
                                          NO                           5,724               43 8542          250 97
                                          EGSL                        24,238               43 8542        1,062 98
                                          ETI                         20,708               43 8542          908.13
                                          Total                      126,581               43.8542        5,551.11

                                       DB ENERGY TRADING LLC/WSPP B
                                           AR                    21,593,680                51 0697    1,102,783.95
                                           LA                    26,009,688                51 0697    1,328,308.08
                                           MS                    14,416,465                51 0697      736,245 05
                                           NO                     4,674,492                51 0697      238,724 80
                                           EGSL                  19,804,486                51 0697    1,011,410.14
                                           ETI                   16,919,189                51 0697      864,058 62
                                           Total                103,418,000                51.0697    5,281,530.64

                                       DOW PIPELINE COMPANY/INTRA-DAY CALL OPTION
                                          EGSL                    2,127,500                62.4643     132,892 87
                                          ETI                     1,572,500                62.4643      98,225.13
                                          Total                   3,700,000                62.4643     231,118.00

                                       DUKE ENERGY HINDS/EXS50
                                          AR                          23,661               20 8211          492 65
                                          LA                          28,499               20 8211          593 37
                                          MS                          15,797               20 8211          328 92
                                          NO                           5,123               20 8211          106 67
                                          EGSL                        21,701               20 8211          451 87
                                          ETI                         18,538               20 8211          385 95
                                          Total                      113,319               20.8211        2,359.43

                                       DUKE ENERGY HINDS/EXS75
                                          AR                          17,266               31 3792          541 80
                                          LA                          20,807               31 3792          652 91
                                          MS                          11,523               31 3792          361 59
                                          NO                           3,726               31 3792          116 93
                                          EGSL                        15,831               31 3792          496.77
                                          ETI                         13,524               31 3792          424 34
                                          Total                       82,677               31.3792        2,594.34

                                       DUKE ENERGY HINDS/EXS90
                                          AR                         180,827               40 9076       7,397.47
                                          LA                         217,804               40 9076       8,909 82
                                          MS                         120,648               40 9076       4,935 34
                                          NO                          39,071               40 9076       1,598 29
                                          EGSL                       165,827               40 9076       6,783 51
                                          ETI                        141,631               40 9076       5,793.70
                                          Total                      865,808               40.9076      35,418.13

                                       DUKEENERGY HOTSPRING/EXS50
                                          AR                          29,273               19 2460          563.40
                                          LA                          35,260               19 2460          678 64
                                          MS                          19,538               19 2460          376 00
                                          NO                           6,334               19 2460          121 89
                                          EGSL                        26,842               19 2460          516 59
                                          ETI                         22,927               19 2460          441 27
                                          Total                      140,174               19.2460        2,697.79

                                       DUKEENERGY HOTSPRING/EXS75
                                          AR                      17,619                   29 9495         527 68
                                          LA                      21,226                   29 9495         635.70
                                          MS                      11,762                   29 9495         352 26
 Attachment Snapshot: 20100826181933                                   RunID: 17029                                   Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                            9-223
                                                                                                                    Exhibit PJC-2
                                                                                                               2011 TX Rate Case
                                                                                                                    Page 62 of 70




 Entergy Electric System                                 Date range - 20100701 through 20100731                                   Attachment 11
 Intra-System Billing-201007RA                        Joint Account / Individual Company Purchases                                      Page 62

                                       Description                      KWH           Mills per KWH        Charge

                                           NO                          3,804               29 9495          113 89
                                           EGSL                       16,148               29 9495          483 64
                                           ETI                        13,806               29 9495          413 52
                                           Total                      84,365               29.9495        2,526.69

                                       DUKEENERGY HOTSPRING/EXS90
                                          AR                         152,741               41 5455       6,345 83
                                          LA                         183,983               41 5455       7,643 50
                                          MS                         101,969               41 5455       4,236 35
                                          NO                          33,061               41 5455       1,373 66
                                          EGSL                       140,121               41 5455       5,821 39
                                          ETI                        119,726               41 5455       4,974 01
                                          Total                      731,601               41.5455      30,394.74

                                       DUKEENERGY HOTSPRING/FREE
                                          AR                             156                0 0000            0 00
                                          LA                             189                0 0000            0 00
                                          MS                             105                0 0000            0 00
                                          NO                              33                0 0000            0 00
                                          EGSL                           144                0 0000            0 00
                                          ETI                            123                0 0000            0 00
                                          Total                          750                0.0000            0.00

                                       ENDURE ENERGY/WSPP A
                                          AR                          283,965              47.7228      13,551.56
                                          LA                          342,048              47.7228      16,323.56
                                          MS                          189,589              47.7228       9,047.72
                                          NO                           61,475              47.7228       2,933 80
                                          EGSL                        260,432              47.7228      12,428.51
                                          ETI                         222,491              47.7228      10,617.85
                                          Total                     1,360,000              47.7228      64,903.00

                                       ENDURE ENERGY/WSPP B
                                          AR                          13,572               26 0000          352 88
                                          LA                          16,348               26 0000          425 04
                                          MS                           9,061               26 0000          235 59
                                          NO                           2,938               26 0000           76.39
                                          EGSL                        12,447               26 0000          323 62
                                          ETI                         10,634               26 0000          276.48
                                          Total                       65,000               26.0000        1,690.00

                                       EPI-ISES ELI   IN
                                            LA                     35,090,137              18.7385     657,536.48
                                            Total                  35,090,137              18.7385     657,536.48

                                       EPI-ISES ENOI IN
                                            NO                     34,395,193              18.7385     644,515 01
                                            Total                  34,395,193              18.7385     644,515.01

                                       ETEC EXCESS-HRSNHRDN
                                           ETI                          4,937              35.7889         176 69
                                           Total                        4,937              35.7889         176.69

                                       ETEC/WSPP B
                                          AR                          244,298              45 0000      10,993.46
                                          LA                          294,260              45 0000      13,241.70
                                          MS                          163,098              45 0000       7,339 39
                                          NO                           52,882              45 0000       2,379 67
                                          EGSL                        224,050              45 0000      10,082.27
                                          ETI                         191,412              45 0000       8,613 51
                                          Total                     1,170,000              45.0000      52,650.00

                                       EXELON FRONTIER 10YR
                                           ETI                     93,424,000              34 9651    3,266,581.59
                                           Total                   93,424,000              34.9651    3,266,581.59

                                       EXELON GENERATION COMPANY LLC/DAILY CALL OPTION
                                           AR                  19,524,239              41.4531          809,340 37
                                           LA                  23,517,077              41.4531          974,855 35
                                           MS                  13,034,879              41.4531          540,336 52
                                           NO                   4,226,539              41.4531          175,202 96
                                           EGSL                17,906,524              41.4531          742,280.74
                                           ETI                 15,297,742              41.4531          634,138 34
                                           Total               93,507,000              41.4531        3,876,154.28


 Attachment Snapshot: 20100826181933                                   RunID: 17029                                   Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                            9-224
                                                                                                                     Exhibit PJC-2
                                                                                                                2011 TX Rate Case
                                                                                                                     Page 63 of 70




 Entergy Electric System                                Date range - 20100701 through 20100731                                     Attachment 11
 Intra-System Billing-201007RA                       Joint Account / Individual Company Purchases                                        Page 63

                                       Description                     KWH           Mills per KWH          Charge

                                       HARD N
                                          ETI                      9,029,000                 54 0920    488,396 52
                                          Total                    9,029,000                 54.0920    488,396.52

                                       J ARON & COMPANY/WSPP B
                                           AR                      4,984,056                 51 3880     256,121 06
                                           LA                      6,003,359                 51 3880     308,501 05
                                           MS                      3,327,478                 51 3880     170,992 64
                                           NO                      1,078,924                 51 3880      55,443.44
                                           EGSL                    4,571,051                 51 3880     234,897.47
                                           ETI                     3,905,132                 51 3880     200,676 84
                                           Total                  23,870,000                 51.3880   1,226,632.50

                                       J.P. MORGAN VENTURES ENERGY CORPORATION/WSPP      A
                                            AR                      13,990                   14 0000        195 86
                                            LA                      16,851                   14 0000        235 91
                                            MS                       9,340                   14 0000        130.76
                                            NO                       3,028                   14 0000         42.39
                                            EGSL                    12,830                   14 0000        179 62
                                            ETI                     10,961                   14 0000        153.46
                                            Total                   67,000                   14.0000        938.00

                                       J.P. MORGAN VENTURES ENERGY CORPORATION/WSPP      B
                                            AR                   1,019,989                   68 0000     69,359.28
                                            LA                   1,228,582                   68 0000     83,543.57
                                            MS                     680,969                   68 0000     46,305.90
                                            NO                     220,801                   68 0000     15,014.43
                                            EGSL                   935,473                   68 0000     63,612.17
                                            ETI                    799,186                   68 0000     54,344.65
                                            Total                4,885,000                   68.0000    332,180.00

                                       JBO/WSPP A
                                           AR                      2,019,305                 71 3696    144,116 87
                                           LA                      2,432,270                 71 3696    173,590 05
                                           MS                      1,348,137                 71 3696     96,215.96
                                           NO                        437,129                 71 3696     31,197.70
                                           EGSL                    1,851,983                 71 3696    132,175 27
                                           ETI                     1,582,176                 71 3696    112,919.15
                                           Total                   9,671,000                 71.3696    690,215.00

                                       JBO/WSPP B
                                           AR                      2,168,386                 60.7315    131,689 50
                                           LA                      2,611,868                 60.7315    158,622.16
                                           MS                      1,447,671                 60.7315     87,919.16
                                           NO                        469,404                 60.7315     28,507.62
                                           EGSL                    1,988,687                 60.7315    120,776.70
                                           ETI                     1,698,984                 60.7315    103,181 86
                                           Total                  10,385,000                 60.7315    630,697.00

                                       KANSAS CITY POWER & LIGHT COMPANY/WSPP A
                                          AR                        300,881                  27.7155      8,339 06
                                          LA                        362,411                  27.7155     10,044.40
                                          MS                        200,875                  27.7155      5,567 35
                                          NO                         65,133                  27.7155      1,805.19
                                          EGSL                      275,952                  27.7155      7,648.14
                                          ETI                       235,748                  27.7155      6,533 86
                                          Total                   1,441,000                  27.7155     39,938.00

                                       MAGNET COVE/EXS75
                                          AR                          3,545                  35 2498        124 96
                                          LA                          4,270                  35 2498        150 52
                                          MS                          2,366                  35 2498         83.40
                                          NO                            767                  35 2498         27.04
                                          EGSL                        3,251                  35 2498        114 59
                                          ETI                         2,777                  35 2498         97.89
                                          Total                      16,976                  35.2498        598.40

                                       MAGNET COVE/EXS90
                                          AR                        164,007                  38 6344      6,336 37
                                          LA                        197,598                  38 6344      7,634 03
                                          MS                        109,555                  38 6344      4,232 55
                                          NO                         35,498                  38 6344      1,371 51
                                          EGSL                      150,472                  38 6344      5,813 28
                                          ETI                       128,521                  38 6344      4,965.45
                                          Total                     785,651                  38.6344     30,353.19
 Attachment Snapshot: 20100826181933                                  RunID: 17029                                     Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                             9-225
                                                                                                                 Exhibit PJC-2
                                                                                                            2011 TX Rate Case
                                                                                                                 Page 64 of 70




 Entergy Electric System                                Date range - 20100701 through 20100731                                 Attachment 11
 Intra-System Billing-201007RA                       Joint Account / Individual Company Purchases                                    Page 64

                                       Description                     KWH           Mills per KWH      Charge


                                       MAGNET COVE/EXSSTSH
                                          AR                         901,963              36 2754     32,719.09
                                          LA                       1,086,406              36 2754     39,409.73
                                          MS                         602,169              36 2754     21,843.89
                                          NO                         195,248              36 2754      7,082.71
                                          EGSL                       827,228              36 2754     30,008.03
                                          ETI                        706,713              36 2754     25,636.30
                                          Total                    4,319,727              36.2754    156,699.75

                                       MDEA CROSSROADS/EXS50
                                          AR                          4,846               24 3350       117 93
                                          LA                          5,838               24 3350       142 08
                                          MS                          3,235               24 3350        78.73
                                          NO                          1,052               24 3350        25.58
                                          EGSL                        4,443               24 3350       108.12
                                          ETI                         3,797               24 3350        92.40
                                          Total                      23,211               24.3350       564.84

                                       MDEA CROSSROADS/EXS75
                                          AR                            977               36.1678        35.34
                                          LA                          1,178               36.1678        42.61
                                          MS                            653               36.1678        23.63
                                          NO                            212               36.1678         7 66
                                          EGSL                          896               36.1678        32.40
                                          ETI                           768               36.1678        27.77
                                          Total                       4,684               36.1678       169.41

                                       MDEA CROSSROADS/EXS90
                                          AR                         34,261               45.1687      1,547 53
                                          LA                         41,256               45.1687      1,863.48
                                          MS                         22,867               45.1687      1,032 90
                                          NO                          7,416               45.1687        334 98
                                          EGSL                       31,427               45.1687      1,419.48
                                          ETI                        26,848               45.1687      1,212 68
                                          Total                     164,075               45.1687      7,411.05

                                       MEAM CANTON 1   IN
                                          MS                         73,000              120 9100      8,826.43
                                          Total                      73,000              120.9100      8,826.43

                                       MEAM CANTON 2   IN
                                          MS                         83,000              120 9100     10,035.53
                                          Total                      83,000              120.9100     10,035.53

                                       MEAM CANTON 3   IN
                                          MS                         84,000              120 9100     10,156.44
                                          Total                      84,000              120.9100     10,156.44

                                       MEAM CANTON 4   IN
                                          MS                         84,000              120 9100     10,156.44
                                          Total                      84,000              120.9100     10,156.44

                                       MEAM CANTON 5   IN
                                          MS                         82,000              120 9100      9,914 62
                                          Total                      82,000              120.9100      9,914.62

                                       MEAM HENDERSON 10 N
                                          MS                         58,000              120 9100      7,012.78
                                          Total                      58,000              120.9100      7,012.78

                                       MEAM HENDERSON 11 N
                                          MS                         59,000              120 9100      7,133 69
                                          Total                      59,000              120.9100      7,133.69

                                       MEAM HENDERSON 2 IN
                                          MS                        524,000              120 9077     63,355.61
                                          Total                     524,000              120.9077     63,355.61

                                       MEAM HENDERSON 4 IN
                                          MS                         72,000              120 9100      8,705 52
                                          Total                      72,000              120.9100      8,705.52

                                       MEAM HENDERSON 5 IN
                                          MS                         72,000              120 9100      8,705 52
 Attachment Snapshot: 20100826181933                                  RunID: 17029                                 Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                         9-226
                                                                                                                   Exhibit PJC-2
                                                                                                              2011 TX Rate Case
                                                                                                                   Page 65 of 70




 Entergy Electric System                                Date range - 20100701 through 20100731                                   Attachment 11
 Intra-System Billing-201007RA                       Joint Account / Individual Company Purchases                                      Page 65

                                       Description                     KWH           Mills per KWH        Charge

                                           Total                     72,000              120.9100        8,705.52

                                       MEAM HENDERSON 6 IN
                                          MS                         73,000              120 9100        8,826.43
                                          Total                      73,000              120.9100        8,826.43

                                       MEAM HENDERSON 7 IN
                                          MS                         76,000              120 9100        9,189.16
                                          Total                      76,000              120.9100        9,189.16

                                       MEAM HENDERSON 8 IN
                                          MS                         74,000              120 9100        8,947 34
                                          Total                      74,000              120.9100        8,947.34

                                       MEAM HENDERSON 9 IN
                                          MS                         54,000              120 9100        6,529.14
                                          Total                      54,000              120.9100        6,529.14

                                       MERRILL LYNCH COMMODIT ES NC/WSPP B
                                          AR                    40,521,612                49 2313    1,994,933.07
                                          LA                    48,808,429                49 2313    2,402,903.87
                                          MS                    27,053,226                49 2313    1,331,865.81
                                          NO                     8,771,914                49 2313      431,852 92
                                          EGSL                  37,164,138                49 2313    1,829,640.85
                                          ETI                   31,749,681                49 2313    1,563,079.13
                                          Total                194,069,000                49.2313    9,554,275.65

                                       MORGAN STANLEY/WSPP A
                                          AR                         51,366               23 8130        1,223.18
                                          LA                         61,868               23 8130        1,473 28
                                          MS                         34,292               23 8130          816 61
                                          NO                         11,118               23 8130          264.74
                                          EGSL                       47,110               23 8130        1,121 82
                                          ETI                        40,246               23 8130          958 37
                                          Total                     246,000               23.8130        5,858.00

                                       NRG CAJUN 3/CAJUN 3
                                          EGSL                    95,955,425              19 5172    1,872,781.39
                                          ETI                     70,923,575              19 5172    1,384,231.31
                                          Total                  166,879,000              19.5172    3,257,012.70

                                       NRG POWER MARKET NG LLC /WSPP A
                                          AR                     6,217,020                26 2779     163,370 39
                                          LA                     7,488,413                26 2779     196,780.76
                                          MS                     4,150,635                26 2779     109,070 04
                                          NO                     1,345,830                26 2779      35,365.61
                                          EGSL                   5,701,912                26 2779     149,833.47
                                          ETI                    4,871,190                26 2779     128,004.73
                                          Total                 29,775,000                26.2779     782,425.00

                                       NRG POWER MARKET NG LLC /WSPP B
                                          AR                     38,603,785               52 0823    2,010,574.87
                                          LA                     46,498,600               52 0823    2,421,752.09
                                          MS                     25,772,818               52 0823    1,342,307.42
                                          NO                      8,356,751               52 0823      435,238.73
                                          EGSL                   35,405,012               52 0823    1,843,976.61
                                          ETI                    30,247,034               52 0823    1,575,336.23
                                          Total                 184,884,000               52.0823    9,629,185.95

                                       NRG POWER MARKET NG LLC /WSPP C
                                          AR                     1,740,348                45.7422      79,607.30
                                          LA                     2,096,255                45.7422      95,887.44
                                          MS                     1,161,899                45.7422      53,147.93
                                          NO                       376,742                45.7422      17,232.89
                                          EGSL                   1,596,150                45.7422      73,011.34
                                          ETI                    1,363,606                45.7422      62,374.10
                                          Total                  8,335,000                45.7422     381,261.00

                                       OCC DENTAL POWER SERVICES/BASE CAPACITY
                                          LA                   219,380,000                35.7590    7,844,813.12
                                          Total                219,380,000                35.7590    7,844,813.12

                                       OCC DENTAL POWER SERVICES/DAY-AHEAD CALL OPTION
                                          LA                    50,188,000            41 0872        2,062,086.80
                                          Total                 50,188,000            41.0872        2,062,086.80
 Attachment Snapshot: 20100826181933                                  RunID: 17029                                   Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                           9-227
                                                                                                                     Exhibit PJC-2
                                                                                                                2011 TX Rate Case
                                                                                                                     Page 66 of 70




 Entergy Electric System                                  Date range - 20100701 through 20100731                                   Attachment 11
 Intra-System Billing-201007RA                         Joint Account / Individual Company Purchases                                      Page 66

                                       Description                       KWH           Mills per KWH        Charge


                                       OCC DENTAL POWER SERVICES/INTRA-DAY CALL OPTION
                                          LA                     9,090,000             51.4329          467,525.10
                                          Total                  9,090,000             51.4329          467,525.10

                                       OCC DENTAL POWER SERVICES/WSPP B
                                          AR                     1,189,742                  63 3591      75,381.01
                                          LA                     1,433,048                  63 3591      90,796.65
                                          MS                       794,302                  63 3591      50,326.31
                                          NO                       257,550                  63 3591      16,318.15
                                          EGSL                   1,091,166                  63 3591      69,135.39
                                          ETI                      932,192                  63 3591      59,062.49
                                          Total                  5,698,000                  63.3591     361,020.00

                                       RAINBOW ENERGY MARKETING CORP/WSPP A
                                           AR                    2,907,333                  32.1174      93,375.97
                                           LA                    3,501,908                  32.1174     112,472 37
                                           MS                    1,941,010                  32.1174      62,340.08
                                           NO                      629,363                  32.1174      20,213.51
                                           EGSL                  2,666,424                  32.1174      85,638.22
                                           ETI                   2,277,962                  32.1174      73,162.10
                                           Total               13,924,000                   32.1174     447,202.25

                                       SAN JAC NTO 1
                                           ETI                       5,722,000              61.7616     353,399.75
                                           Total                     5,722,000              61.7616     353,399.75

                                       SAN JAC NTO 2
                                           ETI                       5,612,000              61.7608     346,601 58
                                           Total                     5,612,000              61.7608     346,601.58

                                       SMEPA/WSPP B
                                          AR                           626,400              89 2640      55,914.95
                                          LA                           754,504              89 2640      67,350.01
                                          MS                           418,200              89 2640      37,330.24
                                          NO                           135,600              89 2640      12,104.24
                                          EGSL                         574,496              89 2640      51,281.84
                                          ETI                          490,800              89 2640      43,810.72
                                          Total                      3,000,000              89.2640     267,792.00

                                       SOUTHERN COMPANY SERVICES NC. AS AGENT FO/WSPP A
                                          AR                     114,840            38 0000               4,363 92
                                          LA                     138,325            38 0000               5,256 35
                                          MS                      76,670            38 0000               2,913.46
                                          NO                      24,860            38 0000                 944 68
                                          EGSL                   105,325            38 0000               4,002 35
                                          ETI                     89,980            38 0000               3,419 24
                                          Total                  550,000            38.0000              20,900.00

                                       SOUTHERN COMPANY SERVICES NC. AS AGENT FO/WSPP B
                                          AR                    2,213,280           128 0000             283,299 91
                                          LA                    2,665,900           128 0000             341,235.19
                                          MS                    1,477,640           128 0000             189,137 93
                                          NO                      479,120           128 0000              61,327.37
                                          EGSL                  2,029,900           128 0000             259,827 20
                                          ETI                   1,734,160           128 0000             221,972.40
                                          Total                10,600,000           128.0000           1,356,800.00

                                       SUEZ ENERGY MARKETING NA INC./WSPP A
                                          AR                      1,808,208                 39 6552      71,705.05
                                          LA                      2,178,009                 39 6552      86,369.35
                                          MS                      1,207,204                 39 6552      47,871.99
                                          NO                        391,432                 39 6552      15,522.47
                                          EGSL                    1,658,371                 39 6552      65,762.74
                                          ETI                     1,416,776                 39 6552      56,182.58
                                          Total                   8,660,000                 39.6552     343,414.18

                                       SUEZ ENERGY MARKETING NA    INC./WSPP B
                                          AR                        11,804,928              48.7041      574,947.70
                                          LA                        14,219,068              48.7041      692,526 53
                                          MS                         7,881,251              48.7041      383,848 90
                                          NO                         2,555,470              48.7041      124,461.73
                                          EGSL                      10,826,823              48.7041      527,309 92
                                          ETI                        9,249,460              48.7041      450,486 22
                                          Total                     56,537,000              48.7041    2,753,581.00
 Attachment Snapshot: 20100826181933                                    RunID: 17029                                   Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                             9-228
                                                                                                                   Exhibit PJC-2
                                                                                                              2011 TX Rate Case
                                                                                                                   Page 67 of 70




 Entergy Electric System                                Date range - 20100701 through 20100731                                   Attachment 11
 Intra-System Billing-201007RA                       Joint Account / Individual Company Purchases                                      Page 67

                                       Description                     KWH           Mills per KWH        Charge


                                       TEA/WSPP A
                                           AR                        233,021              29 3082       6,829.44
                                           LA                        280,677              29 3082       8,226.15
                                           MS                        155,570              29 3082       4,559.48
                                           NO                         50,443              29 3082       1,478.40
                                           EGSL                      213,711              29 3082       6,263.48
                                           ETI                       182,578              29 3082       5,351 05
                                           Total                   1,116,000              29.3082      32,708.00

                                       TENASKA FRONTIER/EXS50
                                          AR                         17,152               21 3697          366 54
                                          LA                         20,660               21 3697          441.49
                                          MS                         11,451               21 3697          244.70
                                          NO                          3,714               21 3697           79.37
                                          EGSL                       15,731               21 3697          336.17
                                          ETI                        13,439               21 3697          287.19
                                          Total                      82,147               21.3697        1,755.46

                                       TENASKA FRONTIER/EXS75
                                          AR                         13,458               32 0598          431.45
                                          LA                         16,210               32 0598          519 69
                                          MS                          8,985               32 0598          288 06
                                          NO                          2,912               32 0598           93.37
                                          EGSL                       12,343               32 0598          395.71
                                          ETI                        10,544               32 0598          338 04
                                          Total                      64,452               32.0598        2,066.32

                                       TENASKA FRONTIER/EXS90
                                          AR                         218,226              39 3082       8,578 04
                                          LA                         262,868              39 3082      10,332.77
                                          MS                         145,651              39 3082       5,725 24
                                          NO                          47,232              39 3082       1,856 64
                                          EGSL                       200,195              39 3082       7,869 32
                                          ETI                        170,975              39 3082       6,720 83
                                          Total                    1,045,147              39.3082      41,082.84

                                       TENASKA/WSPP A
                                          AR                         490,888              59 9025      29,405.41
                                          LA                         591,278              59 9025      35,419.00
                                          MS                         327,729              59 9025      19,631.77
                                          NO                         106,266              59 9025       6,365 63
                                          EGSL                       450,215              59 9025      26,969.02
                                          ETI                        384,624              59 9025      23,039.97
                                          Total                    2,351,000              59.9025     140,830.80

                                       TENASKA/WSPP B
                                          AR                       4,812,638              60.1091      289,283.19
                                          LA                       5,796,845              60.1091      348,443.17
                                          MS                       3,213,034              60.1091      193,132 32
                                          NO                       1,041,808              60.1091       62,622.14
                                          EGSL                     4,413,862              60.1091      265,313 04
                                          ETI                      3,770,813              60.1091      226,660.14
                                          Total                   23,049,000              60.1091    1,385,454.00

                                       UNION POWER PARTNERS/WSPP A
                                           AR                      39,672                 33.1579        1,315.44
                                           LA                      47,786                 33.1579        1,584.49
                                           MS                      26,486                 33.1579          878 22
                                           NO                       8,588                 33.1579          284.76
                                           EGSL                    36,384                 33.1579        1,206.41
                                           ETI                     31,084                 33.1579        1,030 68
                                           Total                  190,000                 33.1579        6,300.00

                                       UNION POWER PARTNERS/WSPP B
                                           AR                  34,397,079                 50 2176    1,727,338.52
                                           LA                  41,431,444                 50 2176    2,080,587.38
                                           MS                  22,964,343                 50 2176    1,153,213.86
                                           NO                   7,446,119                 50 2176      373,926 25
                                           EGSL                31,547,047                 50 2176    1,584,216.71
                                           ETI                 26,950,968                 50 2176    1,353,413.03
                                           Total              164,737,000                 50.2176    8,272,695.75

                                       WESTAR ENERGY INC/WSPP A
                                          AR                       1,447,817              32.4570      46,991.85
 Attachment Snapshot: 20100826181933                                  RunID: 17029                                   Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                           9-229
                                                                                                                   Exhibit PJC-2
                                                                                                              2011 TX Rate Case
                                                                                                                   Page 68 of 70




 Entergy Electric System                                Date range - 20100701 through 20100731                                   Attachment 11
 Intra-System Billing-201007RA                       Joint Account / Individual Company Purchases                                      Page 68

                                       Description                     KWH           Mills per KWH        Charge

                                           LA                      1,743,909              32.4570      56,602.16
                                           MS                        966,608              32.4570      31,373.20
                                           NO                        313,419              32.4570      10,172.73
                                           EGSL                    1,327,853              32.4570      43,098.05
                                           ETI                     1,134,394              32.4570      36,819.01
                                           Total                   6,934,000              32.4570     225,057.00

                                       WESTAR ENERGY INC/WSPP B
                                          AR                     6,170,038                34 5507      213,179 08
                                          LA                     7,431,833                34 5507      256,774 57
                                          MS                     4,119,252                34 5507      142,323 03
                                          NO                     1,335,662                34 5507       46,147.66
                                          EGSL                   5,658,817                34 5507      195,515 95
                                          ETI                    4,834,398                34 5507      167,031.71
                                          Total                 29,550,000                34.5507    1,020,972.00

                                       WESTAR ENERGY INC/WSPP C
                                          AR                        167,040               62 0000      10,356.48
                                          LA                        201,200               62 0000      12,474.40
                                          MS                        111,520               62 0000       6,914 24
                                          NO                         36,160               62 0000       2,241 92
                                          EGSL                      153,200               62 0000       9,498.40
                                          ETI                       130,880               62 0000       8,114 56
                                          Total                     800,000               62.0000      49,600.00

                                       WRIGHTSVILE POWER/EXS75
                                          AR                          7,745               36 3604          281 61
                                          LA                          9,333               36 3604          339 34
                                          MS                          5,171               36 3604          188 00
                                          NO                          1,675               36 3604           60.91
                                          EGSL                        7,107               36 3604          258.42
                                          ETI                         6,069               36 3604          220 69
                                          Total                      37,100               36.3604        1,348.97

                                       WRIGHTSVILE POWER/EXS90
                                          AR                        169,805               42 5289       7,221 54
                                          LA                        204,509               42 5289       8,697.47
                                          MS                        113,362               42 5289       4,821 24
                                          NO                         36,734               42 5289       1,562 29
                                          EGSL                      155,716               42 5289       6,622 53
                                          ETI                       133,010               42 5289       5,656.74
                                          Total                     813,136               42.5289      34,581.81

                                       YAZOO CITY/EXS90
                                          AR                          1,101               44 2334          48.70
                                          LA                          1,324               44 2334          58.57
                                          MS                            734               44 2334          32.46
                                          NO                            237               44 2334          10.49
                                          EGSL                        1,011               44 2334          44.72
                                          ETI                           863               44 2334          38.17
                                          Total                       5,270               44.2334         233.11




 Attachment Snapshot: 20100826181933                                  RunID: 17029                                   Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                           9-230
                                                                                                                  Exhibit PJC-2
                                                                                                             2011 TX Rate Case
                                                                                                                  Page 69 of 70




 Entergy Electric System                       Date range - 20100701 through 20100731                                             Attachment 11
 Intra-System Billing-201007RA         Purchase Capacity and Reserve Sharing Charges - Dollars                                          Page 69



                        Description         System         AR                 LA         MS        NO          EGSL              ETI

          ACADIA PPA - 580 MW - CAP CHG         714,364           0            714,364         0         0             0                0
          CARVILLE - 485 MW - CAP CHG         2,430,000           0                  0         0         0     2,430,000                0
          CONOCO PHILIPS - 100 MW - CAP         165,000           0                  0         0         0        94,875           70,125
          DOW - 100 MW - CAP CHG                150,000           0                  0         0         0        86,250           63,750
          ETEC SAN JAC- 146 MW - CAP CHG        985,500           0                  0         0         0             0          985,500
          EXELON 150 10YR- CAP CHG            1,527,900           0                  0         0         0             0        1,527,900
          EXELON 150 1YR- CAP CHG             1,645,875     343,659            413,938   229,435    74,394       315,185          269,265
          OCC DENTIAL - 480MW - CAP CHG       3,399,552           0          3,399,552         0         0             0                0
          SWPP RESER - CAP CHG                    3,000         626                754       418       136           574              491

          Totals                             11,021,192     344,285          4,528,609   229,853    74,529     2,926,885        2,917,031




 Attachment Snapshot: 20100826181933                          RunID: 17029                                            Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                           9-231
                                                                                                                        Exhibit PJC-2
                                                                                                                   2011 TX Rate Case
                                                                                                                        Page 70 of 70




 Entergy Electric System                            Date range - 20100701 through 20100731                                            Attachment 12
 Intra-System Billing-201007RA                          Fiber Optic Equalization Report                                                     Page 70



                                                                 AR                LA                     MS                    NO

          Inter-Company Circuits(ICC)-Number                              5.50              8.34                   4.00                  4.16
          Inter-Company Circuits(ICC)-Percent                          25 0000           37.9091                18.1818               18.9091
          System Operations Circuits(SOC)-Number                         62.50             46.34                  26.50                 14.66
          System Operations Circuits(SOC)-Percent                      41 6667           30.8933                17.6667                9.7733
          Tele-Processing Circuits(TPC)-Number                           64.00             58.24                  26.00                 23.76
          Tele-Processing Circuits(TPC)-Percent                        37 2093           33.8605                15.1163               13.8140
          Total Circuits-Number                                         132.00            112.92                  56.50                 42.58
          Total Circuits-Percent                                       38 3721           32.8256                16.4244               12.3779

          Total Allocations                                           0 358248          0.343196               0.154639              0.143917


                                                                        ICC              SOC                    TPC
          Total Percent                                                 6 3953           43.6047                50.0000
          Equalization Percent                                         11 3402            0.0000                88.6598

                                                                 AR                LA                     MS                    NO

          Cost of Capital
            Debt Ratio (DR)                                           0.476500          0.502800               0.527000              0.455600
            Bond Cost (i)                                             0 061600          0.067100               0.063400              0 060700
            Preferred Ratio (PR)                                      0 039300          0.019900               0.031800              0 047700
            Preferred Cost (p)                                        0 059900          0.075500               0.056900              0 048200
            Common Ratio (ER)                                         0.484200          0.477400               0.441200              0.496700
            Common Cost (c)                                           0.110000          0.110000               0.110000              0.110000
            Total Cost of Capital (CM)                                0 084968          0.087754               0.083753              0 084591

          Tax Rate (F)                                                0 035895          0.033783               0.031183              0 035609

          Operating Expenses
            Depreciation Factor (D)                                0.0285710         0.0285710              0.0285710              0.0285710
            Insurance Expense (I)                                  0.0040898         0.0012272              0.0040751
            Property Tax (PT)                                      0.0045996         0.0090891              0.0168837              0.0124608
            Franchise Tax (FT)                                     0.0001604                                0.0010224              0.0021793
            Operations & Maintenance (OM)                          0.1539117         0.1111532              0.0465445              0.0486027
            Total Operating Expenses                               0.1913325         0.1500405              0.0970967              0.0918138

          Net Fiber Investment                                   4,893,907.00      5,459,070.00           6,916,494.00          1,399,554.00
           less SOC Investment                                   3,391,907.86      2,514,891.44           1,438,170.49            795,602 56
          Credited Investment                                    1,501,999.14      2,944,178.56           5,478,323.51            603,951.44
          Annual Ownership Cost                                      0 312196         0.271578               0.212033               0 212014
          Net Annual Ownership Cost                                468,917.37        799,572.65           1,161,583.73            128,046 04

          System Average Annual Ownership cost                                                     2,558,119.79 / 18,669,025.00 = 0.2429721
          System Average Monthly Ownership cost                                                                   0.2429721 / 12 = 0.0202477

          Company Responsibilities                               3,771,797.11      3,613,322.84           1,628,109.39          1,515,223.32
          Investment Difference                                  2,269,797.97        669,144.28          (3,850,214.12)           911,271 88

          Payments                                                 45,958.19          13,548.63                                     18,451.16
          Receipts                                                                                           77,957.98




 Attachment Snapshot: 20100826181933                              RunID: 17029                                            Billing Snapshot: 20100826175238



2011 ETI Rate Case                                                                                                9-232
2011 ETI Rate Case




                                                Families and Functions
                            I                                        I
                          Operations                          Corporate Support
                                            I

                     H      Distribution    I                   Accounting Entries


                     H   Customer Service   I                       Corporate


                     H     Generation
                                            I                        Finance

                     y    Transmission      I                   Human Resources
                                                                 & Administration

                                                                   Information
                                                                   Technology

                                                                   Supply Chain



                                                                                     N
9-233




                                                                                     0
                                                                                     .....
                                                                                     .....
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2011 ETI Rate Case                       9-234
2011 ETI Rate Case




                                     Corporate Support Functions & Classes ($ Total ETI Adjusted)

                              I                              I                          I                        I                         I                           I
                                                                                  Accounting             Human Resources               Information
                           Finance                     Corporate                                                                                                Supply Chain
                                                                                    Entries               & Administration             Technology



                                                     Federal PRG
                     Treasury Operations                                         Depreciation            Human Resources          Information Technology        Supply Chain
                                                        Affairs                                                                                            ,_
                          SMcNea/          I-                            I-      S Tumminello      I-       KGardner       I-            J Brown                  J Hunter
                                                     WFerguson
                          $811,510                                                $1,777,986                $9,365,982                 $6,620,998                $1,424,411
                                                       $521,454


                      Financial Services           Utility & Executive
                                                                                Other Expenses            Administration
                          DDoucet          ....       Management
                                                         JDomino
                                                                         ...     S Tumminello
                                                                                                   ...      TP/auche       ....
                         $3,529,673                                               $1,756,009                $644,557
                                                      $1,939,228


                                                  Internal & External          Service Company
                        Tax Services
                         P Galbraith       ...     Communications
                                                     C Herrington
                                                                               Recipient Offsets
                                                                                S Tumminello
                         $2,033,445
                                                       $332,317                       $0


                                                    Legal Services             ncome Tax Expense
                                                       R Sloan                     RRoberts
                                                      $6,691,561                   $510,800


                                                  Regulatory Services
                                                        PMay
                                                      $3,965,085
9-235




                                                                                                                                                                               N
                                                                                                                                                                               0
                                                                                                                                                                               -"'
                                                                                                                                                                               -"'
2011 ETI Rate Case




                             Operations Functions & Classes ($ Total ETI Adjusted)

                                            Domestic Regulated Utility Operations Group


                         I                    I                     I
                                        Customer
                     Distribution                           Transmission         Generation
                                         Service




                     Distribution   Customer Service        Transmission       Energy and Fuel
                     Operations
                     S Corkran
                      $836,799
                                       Operations
                                       A Roman
                                      $6,403,681
                                                        -    Operations
                                                             M Mcculla
                                                             $9,106,198
                                                                           -    Management
                                                                                   PCicio
                                                                                 $3,742,314
                                                                                                 -


                                     Environmental                              Fossil Plant
                     T&D Support
                      S Corkran
                      $750,435
                                       Services
                                       A Roman
                                       $451, 103
                                                        -                       Operations
                                                                                WGarrison
                                                                                $5,265,241
                                                                                                 -


                                                                                  Nelson 6
                                    Retail Operations
                                        A Roman
                                       $1,533,679
                                                        -                        Co-Owner
                                                                                 WGarrison
                                                                                                 -
                                                                                 $8,984,309
9-236
2011 ETI Rate Case




                                       SPO Leadership Team and Areas of Responsibility


                                                           Drew Marsh
                                                             VPSPO


                                                                        Judy Campbell, Executive Secretary

                               I                                             I                         I
                        John Hurstell                                 Patrick Cicio
                                              Stuart Barrett                                     Tony Walz
                             VP                                         Director
                                                 Director                                         Director
                     Strategic Initiatives                         Regulatory Affairs &
                                             Asset Operations                                 Planning Analysis
                                                                   Energy Settlements




                                                           Lee Kellough              Dakin DuBroc
                                 Michelle Thiry
                                                             Director                   Manager
                                    Director
                                                         Power Delivery &        Project & Performance
                              Energy Management
                                                        Technical Services            Management
9-237
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2011 ETI Rate Case                       9-238
2011 ETI Rate Case




                                                                                                                                                                                                                                                                                                               Exhibit PJC-6
                                                                                                                                                                 Entergy Texas, Inc.                                                                                                                      2011 TX Rate Case
                                                                                                                                           Dollars Closed to Plant in Service Including Affliate Component                                                                                                       Page 1 of 1
                                                                                                                                                            July 1, 2009 - June 30, 2011




                      (A)                          (B)                        (C)               (D)                           (E)                        (F)                      (G)                      (H)                (I)          (J)           (K)               (L)               (M)                 (N)              (O)
                                                                                                                                                                                                       Non-Affiliate                                                                     Non-Capital
                                                                                                                                                                                                    Charges Excluding                    Capital       Affiliate   Capital Suspense       Suspense                              Dollars
                                                                                             In Service                                                                                               Cap Susp and                      Suspense       Capital     Charges excluding       Affiliate        Total Affiliate    Closed to
                  Project Code           Project Code Description         Asset Class           Date              Asset Location Description           State               Business Unit             Reimbursements     Reimbursements   Charges      Suspense          Affiliate          Charges            Charges            Plant
                C1PPWS0889       SPO IT 2008                           General Plant           30-Oct-09   CBLE - Capital Billed to LEs             Multi-State   ETI                                         7,529.57             0.00    162.51          121.36                41.15      97,923.69            98,045.05     105,615.77
                C1PPWS0909       SPO Corporate PC Refresh              General Plant           31-Dec-09   CBLE - Capital Billed to LEs             Multi-State   ETI                                         1,393.83             0.00        8.30           6.20                2.10        8,304.03            8,310.23        9,706.16
                C1PPWS0664E      SPO 2007 Server Refresh               General Plant           30-Jun-08   CBLE - Capital Billed to LEs             Multi-State   ETI                                            812.32            0.00      96.76           72.26               24.50        4,305.73            4,377.99        5,214.81
                C1PPWS0774E      SPO Gas Telemetry Migration           General Plant           31-Dec-08   CBLE - Capital Billed to LEs             Multi-State   ETI                                            299.48            0.00        6.63           4.95                1.68        1,327.26            1,332.21        1,633.37
                                                                       General Plant Total                                                                                                                  10,035.20              0.00    274.20          204.77                69.43     111,860.71          112,065.48      122,170.11
                C1PPWS0907       Operations Planning Model Develpmnt   Intangible             30-Oct-09    CBLE - Capital Billed to LEs             Multi-State   ETI                                       24,129.39              0.00      75.99           56.75               19.24        3,764.55            3,821.30       27,969.93
                C1PPWS0883       SPO ECI Project Support 2008          Intangible             30-Oct-09    CBLE - Capital Billed to LEs             Multi-State   ETI                                       17,161.91              0.00      18.58           13.88                4.70        2,553.88            2,567.76       19,734.37
                C1PPWS0911       SPO Add NOxCost to Dispatch Process   Intangible             30-Oct-09    CBLE - Capital Billed to LEs             Multi-State   ETI                                       12,888.60              0.00      47.00           35.10               11.90        2,121.47            2,156.57       15,057.07
                C1PPWS0884       SPO Weekly Procurement Process 2008   Intangible             30-Oct-09    CBLE - Capital Billed to LEs             Multi-State   ETI                                         9,701.76             0.00        0.00           0.00                0.00        1,488.10            1,488.10       11,189.86
                C1PPWS0913       SPO Automated Confirmation Engine     Intangible             30-Oct-09    CBLE - Capital Billed to LEs             Multi-State   ETI                                         8,970.67             0.00      64.94           48.50               16.44        1,444.10            1,492.60       10,479.71
                C1PPWS0912       SPO Deal Eval Redevelopment           Intangible             30-Oct-09    CBLE - Capital Billed to LEs             Multi-State   ETI                                         7,413.87             0.00        7.01           5.23                1.78        1,174.95            1,180.18        8,595.83
                C1PPWS0910       SPO Document Retention Alignment      Intangible             30-Oct-09    CBLE - Capital Billed to LEs             Multi-State   ETI                                         3,591.52             0.00      27.21           20.32                6.89           590.35             610.67        4,209.08
                                                                       Intangible Total                                                                                                                     83,857.72              0.00    240.73          179.77                60.96      13,137.40            13,317.17       97,235.85
                                                                       Grand Total                                                                                                                          93,892.92              0.00    514.93          384.54               130.39     124,998.11          125,382.65      219,405.96
9-239




                                                                                                                                                                                                                                                                                                                               2011 TX Rate Case
                                                                                                                                                                                                                                                                                                                                    Exhibit PJC-6
                                                                                                                                                                                                                                                                                                                                      Page 1 of 1
                                                                                                                                                                    Page 1 of 1
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2011 ETI Rate Case                       9-240
                                                                                                                           ENTERGY TEXAS, INC.                                                                          EXHIBIT PJC-A
2011 ETI Rate Case




                                                                                                         Affiliate Billings - by Witness, Class, and Department                                                      2011 TX Rate Case
                                                                                                               For the Twelve Months Ended June 30, 2011                                                                    Page 1 of 1
                                                                                                                             Amounts in Dollars
                                                                                              (A)              (B)               (C)             (D)         (E)            (F)            (G)           (H)
                                                                                                          Total Billings
                                                                   Billing                               Service Company                                    ETI Per                     Pro Forma      Total ETI
                                             Class                 Entity      Dept         Support         Recipient           Total      All Other BU's   Books        Exclusions      Amount        Adjusted
                     ENERGY AND FUEL MANAGEMENT                  ESI         CP204          1,545,092              45,658      1,590,750       1,373,069     217,681               -          1,282       218,963
                     ENERGY AND FUEL MANAGEMENT                  ESI         CP218            670,285              52,421        722,706         608,009     114,697               -         (1,424)      113,273
                     ENERGY AND FUEL MANAGEMENT                  ESI         CP227          1,056,752              88,917      1,145,669         967,710     177,959               -          3,154       181,114
                     ENERGY AND FUEL MANAGEMENT                  ESI         CP235          1,076,761              52,798      1,129,559       1,037,552       92,007           (392)         2,445        94,059
                     ENERGY AND FUEL MANAGEMENT                  ESI         CP236                 89                    -             89             75            14             -              -             14
                     ENERGY AND FUEL MANAGEMENT                  ESI         CP237                971                    -            971            812          159            (30)            30            159
                     ENERGY AND FUEL MANAGEMENT                  ESI         CP23K            868,238              71,263        939,501         707,570     231,931            (382)         3,043       234,592
                     ENERGY AND FUEL MANAGEMENT                  ESI         CPSLG          1,062,402              67,150      1,129,552         951,196     178,356               -          1,328       179,684
                     ENERGY AND FUEL MANAGEMENT                  ESI         CPSLQ            808,223              69,511        877,734         866,107       11,627           (923)        (1,263)         9,442
                     ENERGY AND FUEL MANAGEMENT                  ESI         SE08B          1,238,559              91,322      1,329,881       1,125,393     204,488            (812)        (2,507)      201,168
                     ENERGY AND FUEL MANAGEMENT                  ESI         SESEE            567,647              51,472        619,119         521,181       97,938            (51)         1,392        99,280
                     ENERGY AND FUEL MANAGEMENT                  ESI         SESKA          1,084,977                1,551     1,086,528         916,884     169,644               -           (106)      169,538
                     ENERGY AND FUEL MANAGEMENT                  ESI         SESKB          1,525,041             137,574      1,662,615       1,403,471     259,144               -          4,105       263,250
                     ENERGY AND FUEL MANAGEMENT                  ESI         SESKC                491                    -            491            491             -             -              -              -
                     ENERGY AND FUEL MANAGEMENT                  ESI         SESKD          1,338,433             107,239      1,445,672       1,283,449     162,223            (581)         3,539       165,181
                     ENERGY AND FUEL MANAGEMENT                  ESI         SESKE          1,250,562              78,031      1,328,594       1,120,970     207,624          (2,563)         2,163       207,224
                     ENERGY AND FUEL MANAGEMENT                  ESI         SESKF          1,336,569             118,596      1,455,165       1,220,425     234,741            (570)        (5,187)      228,983
                     ENERGY AND FUEL MANAGEMENT                  ESI         SESKG                659                    -            659            550          109              -              -            109
                     ENERGY AND FUEL MANAGEMENT                  ESI         SESKH          1,765,397             152,163      1,917,560       1,594,341     323,219            (212)         1,476       324,483
                     ENERGY AND FUEL MANAGEMENT                  ESI         SESKJ          2,966,567             246,827      3,213,393       2,706,497     506,896               -          9,480       516,376
                     ENERGY AND FUEL MANAGEMENT                  ESI         SESKQ            854,394              71,339        925,732         772,863     152,869             (99)       (23,673)      129,098
                     ENERGY AND FUEL MANAGEMENT                  ESI         SESKU            999,442              92,955      1,092,397         941,814     150,582               -          2,851       153,434
                     ENERGY AND FUEL MANAGEMENT                  ESI         SESLA            830,292              75,667        905,959         763,656     142,303            (398)         2,726       144,631
                     ENERGY AND FUEL MANAGEMENT                  ESI         SESLB            373,117              32,386        405,504         345,786       59,718             (9)           712        60,421
                     ENERGY AND FUEL MANAGEMENT                  ESI         SESLC                508                    -            508            427            81             -              -             81
                     ENERGY AND FUEL MANAGEMENT                  ESI         SESLE              1,076                    -         1,076             914          162              -              -            162
                     ENERGY AND FUEL MANAGEMENT                  ESI         SESLT            299,128              27,344        326,472         279,563       46,909             (7)           692        47,594

                     ENERGY AND FUEL MANAGEMENT                  Total ESI                  23,521,673        1,732,183     25,253,856     21,510,774       3,743,083         (7,029)        6,260      3,742,314

                     Total ENERGY AND FUEL MANAGEMENT                                       23,521,673        1,732,183     25,253,856     21,510,774       3,743,083         (7,029)        6,260      3,742,314

                     Total for Witness Cicio, Patrick                                       23,521,673        1,732,183     25,253,856     21,510,774       3,743,083         (7,029)        6,260      3,742,314
9-241




                           Amounts may not add or tie to other schedules due to rounding.                                                                                                                               EXHIBIT PJC-A
                                                                                                                            Cicio, Patrick                                                                                 Page 1 of 1
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2011 ETI Rate Case                       9-242
                                                                                                                                                             ENTERGY TEXAS, INC.                                                                                                  EXHIBIT PJC-B
2011 ETI Rate Case




                                                                                                                                              Affiliate Billings - by Witness, Class and Project                                                                               2011 TX Rate Case
                                                                                                                                                For the Twelve Months Ended June 30, 2011                                                                                             Page 1 of 4
                                                                                                                                                               Amounts in Dollars

                                                                                                                                                                 (A)              (B)           (C)              (D)           (E)         (F)           (G)         (H)
                                                                                                                                                                             Total Billings
                                                                 Billing       Activity /                                                        ESI Billing                Service Company                                  ETI Per                  Pro Forma    Total ETI
                                      Class                      Entity      Project Code                    Activity / Project Description       Method       Support         Recipient        Total       All Other BU's   Books      Exclusions     Amount      Adjusted
                     ENERGY AND FUEL MANAGEMENT                ESI          C1PCN70859      RIVER BEND EXTENDED POWER UPRA                     DIRCTEOI                -                  -            -                -           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          C1PPRNE010      New Nuclear -Regulatory Filing                     NWDVRBGG           (9,843)              (774)     (10,617)         (10,617)          -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          C1PPRTOSOF      RTO Implement Software ALLCOS                      LOADOPCO           13,959              1,480       15,439           12,876       2,563       (2,563)            -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          C1PPSP0008      SPO ELL&ENOI Purchase Option I                     OWNISES2         (174,936)            (7,788)    (182,724)        (182,724)          -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          C6PCN32144      GRAND GULF EXTENDED POWER UPRA                     DIRCTSER           15,927              1,458       17,385           17,385           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          C6PCN70858      RIVER BEND EXTENDED POWER UPRA                                         3,104                283        3,386            3,386           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          C6PPGN0020      New Nuclear Reg Filing EGSL On                     DIRECTLG            6,813                537        7,350            7,350           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          C6PPLN0020      New Nuclear Reg Filing ELL Ong                     DIRCTELI            8,823                695        9,518            9,518           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          C6PPMN0020      New Nuclear Reg Filing EMI Ong                     DIRCTEMI                -                  -            -                -           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          C6PPN66876      Cladding Failure Root Cause &                      DIRCTWF3            5,748                545        6,293            6,293           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          C6PPRN0002      New Nuclear - Entergy                              DIRCTR1                 -                  -            -                -           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          C6PPRN0010      New Nuclear - Regulatory Filin                     DIRCTR1                 -                  -            -                -           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          C6PPSP0012      SPO Project Gator Transact/Tra                     DIRCTELI          143,114              4,441      147,555          147,555           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          C6PPSP0029      SPO Evange ine                                     DIRCTELI           41,666              2,947       44,613           44,613           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          C6PPSP0030      SPO Ouachita Fuel Meter Common                     DIRCTEAI              539                 45          584              584           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          C6PPSP0038      SPO Project Lamar Transaction                      DIRCTEAI          381,462             11,378      392,839          392,839           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          C6PPSP0045      SPO Real Time Calcasieu RTU                        DIRECTLG           25,835                156       25,991           25,991           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          C6PPSP0046      SPO Project Burnet Transaction                     DIRCTEMI          414,076             11,232      425,307          425,307           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          C6PPWGP516      SBC CIP Compliance                                 DIRECTTX              120                  -          120                -         120         (120)            -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          C6PPWS0534      System Planning Pet Coke Repow                     DIRCTELI              374                 11          384              384           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          C6PPWS0628      SPO W-WOTAB CT Development Spe                     DIRECTTX                -                  -            -                -           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          C6PPWS0783      Ninemile 6 Development                             DIRCTELI           34,977              3,274       38,251           38,251           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          C6PPWS0984      SPO EGSL Purchase of Ouach ta                      DIRECTLG                -                  -            -                -           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          E1PPEFF003      EAI ENERGY EFFCNCY NON-INCREME                     DIRCTEAI           11,515              1,145       12,660           12,660           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCCPM001      CORPORATE PERFORMANCE MANAGEME                     ASSTSALL                -                  -            -                -           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCCSPEAI      SYSTEM PLANNING - EAI                              DIRCTEAI           33,801              3,163       36,965           36,965           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCCSPEEI      SYSTEM PLANNING - NONREG - EEI                     ASSTNREG              548                 48          596              596           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCCSPELI      SYSTEM PLANNING - ELI                              DIRCTELI           30,852              2,782       33,634           33,634           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCCSPEMI      SYSTEM PLANNING - EMI                              DIRCTEMI            3,103                276        3,379            3,379           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCCSPENO      SYSTEM PLANNING - ENOI                             DIRCTENO           34,626              3,063       37,689           37,689           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCCSPGSL      SYSTEM PLANNING - EGSI-LA                          DIRECTLG           15,257              1,350       16,607           16,607           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCCSPGST      SYSTEM PLANNING - EGSI-TX                          DIRECTTX           22,828              2,070       24,898                -      24,898            -           515      25,413
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCCSPSYS      SYSTEM PLANNING AND STRATEGIC                      ASSTSALL          290,004                525      290,529          261,342      29,187            -            13      29,199
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCCSPUTI      SYSTEM PLANNING & STRATEGIC AD                     LOADOPCO        2,778,700            170,067    2,948,767        2,487,717     461,050            -         5,541     466,591
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCE14420      REGULATORY AFFAIRS - EAI                           DIRCTEAI           19,919              1,638       21,556           21,556           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCE14423      REGULATORY AFFAIRS - EMI                           DIRCTEMI            8,233                760        8,993            8,993           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCF07300      CORP PLANNING & ANALYSIS- REGU                     CUSTEGOP           16,968              1,166       18,135           15,634       2,500            -            37       2,537
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCF21600      CORP RPTG ANALYSIS & POLICY AL                     GENLEDAL                -                  -            -                -           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCFBLETR      BELOW THE LINE EXPENSES -ETR                       DIRCTETR                -                  -            -                -           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCFBLFOS      BELOW THE LINE - FOSSIL OPERAT                     CAPAOPCO            7,368                  -        7,368            6,571         797         (797)            -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCFF1003      BOARD SUPPORT                                      ASSTSALL            5,434                377        5,812            5,233         578            -             8         587
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCFVARAS      ADMIN SUPRT - VARIBUS CORPORAT                     DIRECTLG           41,139              3,778       44,917           44,917           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCSYSAGR      SYSTEM AGREEMENT-2001                              CUSEOPCO          381,179             30,815      411,994          351,119      60,875            -         1,599      62,474
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCSYSRAS      SYSTEM REGULATORY AFFAIRS-STAT                     CUSTEGOP            2,691                265        2,956            2,546         410            -            13         423
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCW15822      RESOURCE PLANNING COORDINATOR                      LOADOPCO          122,890             11,496      134,385          113,301      21,085            -           694      21,779
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCW15830      SYSTEM GENERATION PLANNING                         LOADOPCO        1,726,349            155,656    1,882,005        1,586,195     295,809            -         5,726     301,535
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCW15840      PLANNING MODELING & ANALYSIS G                     LOADOPCO          295,253             26,854      322,107          271,607      50,501            -           960      51,461
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCW18100      OPNS-GAS SUPPLY                                    CAPXCOPC        1,150,758            104,642    1,255,400        1,083,837     171,563            -         3,266     174,829
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCW18200      OPNS-OIL SUPPLY                                    OWNISFI           137,062             12,761      149,823          149,823           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCW18300      OPNS-COAL SUPPLY                                   COALARGS          770,795             66,064      836,859          836,859           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCW19501      WHOLESALE PURCHASING & SALES                       LOADOPCO        1,620,269            116,517    1,736,786        1,462,875     273,911            -         5,282     279,193
9-243




                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCW19502      WHOLESALE TRXN - EAI CUSTOMERS                     DIRCTEAI               56                  -           56               56           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCW19510      ENERGY MANAGEMENT OPERATIONS                       LOADOPCO        2,469,933            219,678    2,689,611        2,264,551     425,060            -         7,958     433,019
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCW19511      ENERGY MANAGEMENT OPERATIONS P                     LOADOPCO        1,548,975            133,113    1,682,089        1,416,167     265,922            -         4,977     270,899
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCW19512      ENERGY MGMT - FUEL & ENERGY AN                     LOADOPCO        1,015,950             90,454    1,106,404          931,546     174,858            -         3,336     178,195
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCW29607      POWER SYSTEM ACCOUNTING                            LOADWEPI          420,638             38,815      459,453          387,423      72,031            -         1,389      73,419
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCW51400      SFI FUEL OIL O&M                                   DIRCTSFI              251                 27          278              278           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCW54035      VICE PRESIDENT OF ENERGY MANAG                     LOADOPCO        1,073,545                310    1,073,855          905,703     168,152            -             8     168,160
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCWE0012      1998 FUELS MANAGEMENT TELEMETR                     CAPAOPCO          140,071                  -      140,071          124,928      15,143            -             -      15,143
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCWE0034      DIRECTOR - PLANT SUPPORT                           CAPAOPCO                -                  -            -                -           -            -             -           -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCWE0046      PLANT SUPPORT SERVICES - BIG C                     ASSTTXLG           29,487              2,456       31,943           18,773      13,169            -           265      13,435
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCWE0058      AWARDS & RECOGNITIONS PROGRAM                      LOADOPCO           11,430              1,572       13,003           11,042       1,961            -            43       2,004

                           Amounts may not add or tie to other schedules due to rounding.                                                                                                                                                                                         EXHIBIT PJC-B
                                                                                                                                                                Cicio, Patrick                                                                                                       Page 1 of 4
                                                                                                                                                              ENTERGY TEXAS, INC.                                                                                                        EXHIBIT PJC-B
2011 ETI Rate Case




                                                                                                                                               Affiliate Billings - by Witness, Class and Project                                                                                     2011 TX Rate Case
                                                                                                                                                 For the Twelve Months Ended June 30, 2011                                                                                                   Page 2 of 4
                                                                                                                                                                Amounts in Dollars

                                                                                                                                                                  (A)              (B)         (C)             (D)           (E)           (F)              (G)           (H)
                                                                                                                                                                              Total Billings
                                                                 Billing       Activity /                                                         ESI Billing                Service Company                               ETI Per                       Pro Forma      Total ETI
                                      Class                      Entity      Project Code                     Activity / Project Description       Method       Support         Recipient      Total      All Other BU's   Books        Exclusions        Amount        Adjusted
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCWE0064      LONG TERM ENERGY                                    LOADOPCO          327,588             28,335    355,923         299,950       55,973                 -        1,019         56,992
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCWE0092      EMS OPERATIONS & MAINTENANCE S                      LOADOPCO           89,299                  -     89,299          74,476       14,823                 -           279        15,102
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCWE0133      EMO INFORMATION TECHNOLOGY SUP                      LOADOPCO            7,521                  -      7,521           6,273        1,248                 -             -         1,248
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCWE0135      NEL. 6 JOINT OWNERSHIP PART. A                      DIRECTLG            4,929                463      5,392           5,392             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCWE0138      POWER CONTRACTS                                     LOADOPCO              508                  -         508            427            81                -             -            81
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCWE0140      EMO REGULATORY AFFAIRS                              LOADOPCO          447,019             40,575    487,594         411,164       76,430                 -        1,862         78,292
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCWE0151      FOSSIL DIVERSITY INITIATIVE -                       CAPAOPCO               68                  5          73             65             8                -             0              8
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCZU1571      EGSI TX FUEL RELATED MATTERS                        DIRECTTX               67                  -          67              -           67                 -             -            67
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PCZU1582      EGSI LA 3RD EARNINGS REVIEW                         DIRECTLG              (43)                 -         (43)           (43)            -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPADSENT      Analytic/Decision Support-Ente                      ASSTSALL              614                  -         614            555            58                -             -            58
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPADTFL9      ELL Fuel Audit 2005-2009                            DIRCTELI            1,541                141      1,682           1,682             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPAMPDEV      Advanced Mgmt Dev Program                           EMPLOYAL           22,486                  -     22,486          21,430        1,056                 -             -         1,056
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPAPSCLG      APSC Complaint - FERC Investig                      CUSEOPCO                -                  -           -              -             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPDOWPPA      Dow 3 Year PPA (2011-2014)                          DIRECTLG            1,622                151      1,773           1,773             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPDSMALL      DSM/Energy Efficiency -All Jur                      CUSTEGOP            3,059                258      3,318           2,858          460                 -          (460)             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPE14432      EAI SPP RTO Study                                   DIRCTEAI            3,545                366      3,910           3,910             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPE14434      EAI POST SYS AGMT INCREMENTAL                       DIRCTEAI           17,270              1,376     18,646          18,646             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPE14435      EAI POST SYS AGMT NON-INCREMEN                      DIRCTEAI            2,616                270      2,886           2,886             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPE14436      EAI MISO RTO STUDY                                  DIRCTEAI            1,103                 93      1,196           1,196             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPEAI011      EAI 2011 Rate Filing                                DIRCTEAI            1,337                141      1,479           1,479             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPEAIMIS      MISO Transition EAI Path 1 cos                      DIRCTEAI           39,150              3,057     42,207          42,207             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPEAIPAT      Maintain EAI Paths 2 and 3 RTO                      DIRCTEAI            7,481                565      8,046           8,046             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPEGSLMI      MISO Transition EGSL costs                          DIRECTLG              235                  -         235            235             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPELLMIS      MISO Transition ELL costs                           DIRCTELI              235                  -         235            235             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPEMI381      EMI-2010 PMR Docket 2008-UN-38                      DIRCTEMI            1,048                109      1,157           1,157             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPEMI884      EMI-2010 ECR Docket 2008-UN-88                      DIRCTEMI            1,365                139      1,504           1,504             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPEMIMIS      MISO Transition EMI costs                           DIRCTEMI            1,299                 84      1,382           1,382             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPENOIMI      MISO Transition ENOI costs                          DIRCTENO               47                  4          50             50             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPETIMIS      MISO Transition ETI costs                           DIRECTTX              358                 27         385              -          385                 -          (385)             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPINVDOJ      DOJ Anti Trust Investigation                        CUSEOPCO           18,258              1,510     19,768          16,851        2,917                 -            77         2,994
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPISP717      Integration Planning Studies 7                      LOADOPCO           40,136              3,855     43,991          36,925        7,066                 -           149         7,215
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPMSEE10      MS Docket2010-AD-02 Ergy Effic                      DIRCTEMI                -                  -           -              -             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPMSFA10      2010 EMI Fuel Aud t                                 DIRCTEMI           27,307              2,651     29,959          29,959             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPPGA010      PGA Audit 2010                                      DIRECTLG            3,163                301      3,463           3,463             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPR56620      WHOLESALE - EGSI LA                                 DIRECTLG                -                  -           -              -             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE001      SPO NISCO JOPOA MANAGEMENT EXP                      DIRECTLG            2,404                229      2,633           2,633             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE002      SPO 2009 Renewable RFI Expense                      LOADOPCO           10,073                983     11,056           9,405        1,651                 -            34         1,685
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE003      SPO Summer 2009 RFP Expense                         LOADOPCO          146,425             14,002    160,427         136,260       24,168                 -           358        24,526
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE004      SPO Summer09RFP IM&PropslSubmt                      LOADOPCO          269,064                  -    269,064         227,046       42,018                 -             -        42,018
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE006      SPO ISES Mining Asset Evaluati                      DIRCTEAI                -                  -           -              -             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE007      SPO July 2009 Flexible Baseloa                      LOADOPCO                -                  -           -              -             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE008      SPO July 09 Flex Baseld RFP IM                      LOADOPCO                -                  -           -              -             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE010      SPO Diversity Initiative                            LOADOPCO            4,168                253      4,422           3,725          697                 -            (4)          693
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE011      SPO NISCO Contract                                  DIRECTLG           28,482              2,396     30,879          30,879             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE013      SPO PROMOD License for LPSC                         CUSELGLA           70,620                  -     70,620          70,620             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE015      SPO Compliance and Business Su                      LOADOPCO          860,093             78,087    938,180         789,566     148,614                  -        2,649       151,263
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE016      Addendum-WE0418 Summer 08 IM                        LOADOPCO                -                  -           -              -             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE017      SPO 2010 Renewable RFP                              LOADOPCO           80,022              3,874     83,896          71,371       12,525                 -           141        12,666
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE018      SPO VP of Strategic Initiative                      LOADOPCO          371,895             34,263    406,158         343,181       62,977                 -        1,120         64,097
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE019      SPO IT Infrastructure Maint.                        LOADOPCO          100,713                  -    100,713          83,996       16,718                 -             -        16,718
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE020      SPO SOFTWARE SUPPORT/LICENSING                      LOADOPCO           24,665                  -     24,665          20,571        4,094                 -             -         4,094
9-244




                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE022      SPO Communications Infrastruct                      LOADOPCO           52,135                  -     52,135          43,481        8,654                 -             -         8,654
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE024      SPO Power De ivery & Tech Serv                      LOADOPCO          348,447             30,104    378,551         318,892       59,659                 -        1,130         60,789
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE025      SPO 2010 Renewable RFP - LA on                      CUSELGLA            7,915             26,865     34,780          34,780             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE027      SPO ESI Project Houston PPA                         DIRCTESI                -                  -           -              -             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE028      SPO CIP Expense                                     LOADOPCO           85,786                  -     85,786          71,547       14,240                 -             -        14,240
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE038      SPO Pwr Del & Tech Svcs - EMI                       DIRCTEMI                -                  -           -              -             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE042      SPO Expense ISES Purchase Opti                      OWNISES2          245,805             11,722    257,526         257,526             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE045      PMO Support Initiative - EAI                        DIRCTEAI            2,817                234      3,051           3,051             -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE047      SPO Telecommunications                              LOADOPCO            6,086                  -      6,086           5,075        1,010                 -             -         1,010
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE048      SPO Cottonwood Expense                              LOADOPCO              486                 37         522            435            87                -             2            89
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPE049      SPO 2011 EAI RFP                                    DIRCTEAI            4,968                318      5,286           5,286             -                -             -              -

                           Amounts may not add or tie to other schedules due to rounding.                                                                                                                                                                                                EXHIBIT PJC-B
                                                                                                                                                                 Cicio, Patrick                                                                                                             Page 2 of 4
                                                                                                                                                             ENTERGY TEXAS, INC.                                                                                                 EXHIBIT PJC-B
2011 ETI Rate Case




                                                                                                                                              Affiliate Billings - by Witness, Class and Project                                                                              2011 TX Rate Case
                                                                                                                                                For the Twelve Months Ended June 30, 2011                                                                                            Page 3 of 4
                                                                                                                                                               Amounts in Dollars

                                                                                                                                                                 (A)             (B)         (C)            (D)           (E)          (F)           (G)          (H)
                                                                                                                                                                            Total Billings
                                                                 Billing       Activity /                                                        ESI Billing               Service Company                              ETI Per                   Pro Forma     Total ETI
                                      Class                      Entity      Project Code                    Activity / Project Description       Method       Support        Recipient      Total     All Other BU's   Books       Exclusions     Amount       Adjusted
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPSENI      Strategic Planning SVCS-ENI                        DIRCTENU              497                39       536             536            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPSENT      Strategic Planning SVCS-Enterg                     ASSTSALL           16,152             1,416    17,568          15,832        1,736            -            37         1,774
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPSPSREG      Strategic Planning SVCS-Utilit                     ASSTSREG            5,833               459     6,292           5,352          939            -            20           960
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPTCGS11      TX Docket Competitive Generati                     DIRECTTX            2,870               267     3,137               -        3,137            -            66         3,203
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPTDERSC      Entergy Regional State Committ                     LOADOPCO          271,962            19,669   291,631         244,380       47,250            -         1,014        48,265
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPTDERSD      MISO Transition ALL OPCO                           LOADOPCO          122,670             8,589   131,259         109,471       21,788            -       (21,788)            -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPTDHY11      Transmission Compliance FERC A                     TRSBLNOP              144                15       159             140           19            -             1            19
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPUD0802      ENO Integrated Resource Plan                       DIRCTENO            6,267               462     6,729           6,729            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPUTLDER      Util ty Derivatives Compliance                     LOADOPCO            2,881               261     3,142           2,620          521            -            11           533
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPWE0292      System Planning Asset Manageme                     LOADOPCO          319,863            27,284   347,147         291,842       55,305            -           952        56,258
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPWE0315      Dir. Southeast Region-TXT_ ELI                     CAPASTHN           18,259             1,717    19,976          19,976            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPWE0402      SPO Regulatory Compliance                          LOADOPCO          545,842            47,326   593,168         499,258       93,910            -         1,882        95,792
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPWE0403      SPO Performance Mngmnt/Special                     LOADOPCO          437,200            36,298   473,498         398,296       75,202            -         1,619        76,821
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPWE0420      SPO EGSL-SupplyProcuremt/Asset                     DIRECTLG            4,225               356     4,581           4,581            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPWE0432      SPOManagement of Sys IRP Activ                     LOADOPCO            1,286               107     1,393           1,177          216            -             7           223
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPWE0437      SPO Expense KGen Hinds                             DIRCTEMI                -                 -         -               -            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPWE0438      SPO Expense KGen Hot Springs                       DIRCTEAI                -                 -         -               -            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPWE0478      Parkwood II Safety Team                            CAPAOPCO            8,234                 -     8,234           7,343          890            -          (147)          743
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPWE0516      EPA Section 114 Request for In                     DIRCTEAI            3,836               365     4,201           4,201            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPWET300      SPO 2008 Western Region RFP-Te                     DIRECTTX              473                39       512               -          512            -            11           523
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPWET301      SPO ETI-SupplyProcuremt/AssetM                     DIRECTTX                -                 -         -               -            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPWET302      SPO 2008 Winter Western Region                     DIRECTTX            4,218               388     4,607               -        4,607            -            91         4,698
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPWET303      SPO2008WinterWestnRegionRFP-IM                     DIRECTTX            4,200                 -     4,200               -        4,200            -             -         4,200
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPWET304      SPO Frontier 10 Year PPA                           DIRECTTX               88                 7        95               -           95            -             2            97
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPWET305      SPO WWOTAB Expense                                 DIRECTTX                -                 -         -               -            -            -            (0)           (0)
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPWET306      SPO 2011 Western Region RFP                        DIRECTTX           87,224             5,621    92,845               -       92,845            -         1,563        94,408
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPWET307      SPO2011WestnRegionRFP-IM&PropS                     DIRECTTX           19,469                 -    19,469               -       19,469            -             -        19,469
                     ENERGY AND FUEL MANAGEMENT                ESI          F3PPWET308      SPO Calpine PPA/Project Housto                     DIRECTTX           86,588             8,357    94,945               -       94,945            -         1,996        96,941
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PC25116F      ELI FUEL AUDIT 2001                                DIRCTELI            1,394               117     1,511           1,511            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PCE13611      GENERAL LITIGATION-ENOI                            DIRCTENO            2,733               257     2,990           2,990            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PCE13751      GENERAL LITIGATION- EGSI-LA                        DIRECTLG            4,399               388     4,787           4,787            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PCE13759      JENKINS CLASS ACTION SUIT                          DIRECTTX           34,881             2,988    37,870               -       37,870            -         1,007        38,876
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PCEDIVER      DIVERSITY TRAINING                                 DIRCTESI              495                 -       495             495            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PCGSL351      ELI 2001 SYSTEM AGREEMENT CASE                     DIRCTELI            1,234               125     1,359           1,359            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PCGSL500      EGS FUEL AUDIT                                     DIRECTLG            1,794               102     1,896           1,896            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PCSVCAWD      SERVICE AWARDS                                     DIRCTESI            4,799                 -     4,799           4,799            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PCZCDEPT      SUPERVISION & SUPPORT - CORPOR                     LBRCORPT           15,051             1,317    16,368          15,927          441            -            10           451
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PCZU1422      REGULATORY AFFAIRS - LP&L                          DIRCTELI           10,036               985    11,021          11,021            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PCZU1424      REGULATORY AFFAIRS - NOPSI                         DIRCTENO           37,547             3,228    40,775          40,775            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PCZU1425      REGULATORY COORDINAT.-ELI & EG                     CUSELPSC              566                58       624             624            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PCZU1573      REGULATORY AFFAIRS -- 100% EGS                     DIRECTTX                -                 -         -               -            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PCZU1574      REGULATORY AFFAIRS - 100% TX G                     DIRECTTX           33,986             2,760    36,745               -       36,745            -           719        37,464
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PCZU1579      REGULATORY AFFAIRS -- 100% EGS                     DIRECTLG            5,045               439     5,485           5,485            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PCZUDEPX      DEPRECIATION AND AMORTIZATION                      ESIDEPRE            1,450                 -     1,450           1,450            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PCZXNLDW      NEW LEADERSHIP DEVELOPMENT WOR                     EMPLOREG               35                 -        35              33            2            -             -             2
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PCZZ4070      IMPACT AWARDS                                      DIRCTESI              191                 -       191             191            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PP10011U      Show Cause Docket No. 10-011-U                     DIRCTEAI          169,027            14,225   183,252         183,252            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PP27836P      ELI/EGS Purchase of Perryville                     DIRCTELI               14                 -        14              14            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PP4RFERC      FERC Audit                                         LVLSVCAL            1,999               187     2,185           1,975          210            -             7           217
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PPBCNAVF      Avian Flu Contingency Planning                     EMPLOYAL                -                 -         -               -            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PPBULKPW      Minimize of Bulk Power Supply                      LOADOPCO           58,303             4,996    63,299          52,958       10,341            -           210        10,551
9-245




                     ENERGY AND FUEL MANAGEMENT                ESI          F5PPDOEETR      DOE-Dept of Energy Studies Coo                     LOADOPCO              458               186       644             544          100            -             7           106
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PPE14427      Regulatory Info RFIs-EAI-Dock                      DIRCTEAI            6,118               543     6,660           6,660            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PPETX009      2009 Texas Rate Case Support                       DIRECTTX           15,273             1,828    17,101               -       17,101       (3,549)      (13,552)            -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PPETX011      2011 Texas Rate Case Support                       DIRECTTX              222                25       247               -          247            -             8           255
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PPFALCON      Project Falcon                                     DIRECTNI            4,987               382     5,370           5,370            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PPFERCCM      FERC Compliance Program                            EMPLOREG               67                 -        67              63            4            -             -             4
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PPHREXEC      HR Executive Financial Counsel                     ASSTSALL                -                 -         -               -            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PPLEGRB3      Regulatory Filings - River Ben                     CUSELGLA              176                 -       176             176            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PPMSFA09      2009 EMI Fuel Aud t Horne Grou                     DIRCTEMI            1,113                98     1,210           1,210            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PPMSFA9A      2009 EMI Fuel Aud t McFadden G                     DIRCTEMI              518                57       575             575            -            -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI          F5PPPAPDIS      Paper Barrier Case                                 DIRCTEAI                -                 -         -               -            -            -             -             -

                           Amounts may not add or tie to other schedules due to rounding.                                                                                                                                                                                        EXHIBIT PJC-B
                                                                                                                                                                Cicio, Patrick                                                                                                      Page 3 of 4
                                                                                                                                                                ENTERGY TEXAS, INC.                                                                                                        EXHIBIT PJC-B
2011 ETI Rate Case




                                                                                                                                                 Affiliate Billings - by Witness, Class and Project                                                                                     2011 TX Rate Case
                                                                                                                                                   For the Twelve Months Ended June 30, 2011                                                                                                   Page 4 of 4
                                                                                                                                                                  Amounts in Dollars

                                                                                                                                                                    (A)              (B)           (C)             (D)          (E)           (F)              (G)           (H)
                                                                                                                                                                                Total Billings
                                                                    Billing       Activity /                                                        ESI Billing                Service Company                                 ETI Per                      Pro Forma      Total ETI
                                           Class                    Entity      Project Code                    Activity / Project Description       Method       Support         Recipient        Total      All Other BU's   Books       Exclusions        Amount        Adjusted
                     ENERGY AND FUEL MANAGEMENT                   ESI          F5PPSPE044      PMO Support Initiative-System-                     LOADOPCO          74,598               6,137      80,735           67,333       13,401                -       (13,401)            -
                     ENERGY AND FUEL MANAGEMENT                   ESI          F5PPSPPCBA      ICT/RTO Cost Benefit Analysis                      LOADOPCO          34,464               3,240      37,704           31,745        5,958                -        (5,958)            -
                     ENERGY AND FUEL MANAGEMENT                   ESI          F5PPSUPICT      Support of ICT                                     LOADOPCO          71,151               6,083      77,234           64,739       12,495                -           247        12,742
                     ENERGY AND FUEL MANAGEMENT                   ESI          F5PPWE0485      2010 EPA Request for Informati                     CAPAOPCO               45                  4           48              43            5                -             0             5
                     ENERGY AND FUEL MANAGEMENT                   ESI          F5PPZUWELL      Entergy Wellness Program                           EMPLOYAL          11,227                 840      12,068           11,478          590                -            13           603
                     ENERGY AND FUEL MANAGEMENT                   ESI          F5PPZZ580B      REGULATORY AFFAIRS-A&G                             CUSTEGOP           1,064                  82        1,146             988          158                -             3           161

                     ENERGY AND FUEL MANAGEMENT                   Total ESI                                                                                       23,521,673         1,732,183   25,253,856     21,510,774     3,743,083       (7,029)           6,260     3,742,314

                     Total ENERGY AND FUEL MANAGEMENT                                                                                                             23,521,673         1,732,183   25,253,856     21,510,774     3,743,083       (7,029)           6,260     3,742,314

                     Total Cicio Patrick                                                                                                                          23,521,673         1,732,183   25,253,856     21,510,774     3,743,083       (7,029)           6,260     3,742,314
9-246




                              Amounts may not add or tie to other schedules due to rounding.                                                                                                                                                                                               EXHIBIT PJC-B
                                                                                                                                                                   Cicio, Patrick                                                                                                             Page 4 of 4
                                                                                                                                                                            ENTERGY TEXAS, INC.                                                                                                                   EXHIBIT PJC-C
2011 ETI Rate Case




                                                                                                                                                       Affiliate Billings - by Witness, Class, Department and Project                                                                                          2011 TX Rate Case
                                                                                                                                                                 For the Twelve Months Ended June 30, 2011                                                                                                           Page 1 of 11
                                                                                                                                                                              Amounts in Dollars
                                                                                                                                                                                            (A)             (B)            (C)              (D)          (E)          (F)           (G)             (H)
                                                                                                                                                                                                        Total Billings
                                                                                            Activity / Project                                                          ESI BIlling                    Service Company                                  ETI Per                  Pro Forma        Total ETI
                                      Class                    Billing Entity      Dept           Code                            Activity / Project Description         Method           Support         Recipient        Total       All Other BU's   Books      Exclusions     Amount          Adjusted
                     ENERGY AND FUEL MANAGEMENT                ESI              CP204       E1PPEFF003           EAI ENERGY EFFCNCY NON-INCREME                       DIRCTEAI               11,515              1,145       12,660           12,660           -             -            -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP204       F3PCCSPGST           SYSTEM PLANNING - EGSI-TX                            DIRECTTX                1,032                105        1,137                -       1,137             -           24           1,161
                     ENERGY AND FUEL MANAGEMENT                ESI              CP204       F3PCCSPSYS           SYSTEM PLANNING AND STRATEGIC                        ASSTSALL              257,660                151      257,811          231,925      25,886             -            4          25,890
                     ENERGY AND FUEL MANAGEMENT                ESI              CP204       F3PCCSPUTI           SYSTEM PLANNING & STRATEGIC AD                       LOADOPCO            1,189,449             43,430    1,232,879        1,042,896     189,983             -        1,714         191,697
                     ENERGY AND FUEL MANAGEMENT                ESI              CP204       F3PCE14420           REGULATORY AFFAIRS - EAI                             DIRCTEAI                2,599                149        2,748            2,748           -             -            -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP204       F3PPAMPDEV           Advanced Mgmt Dev Program                            EMPLOYAL                4,112                  -        4,112            3,921         192             -            -             192
                     ENERGY AND FUEL MANAGEMENT                ESI              CP204       F3PPDSMALL           DSM/Energy Efficiency -A l Jur                       CUSTEGOP                3,059                258        3,318            2,858         460             -         (460)              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP204       F3PPEAI011           EAI 2011 Rate Fi ing                                 DIRCTEAI                1,337                141        1,479            1,479           -             -            -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP204       F3PPSPE013           SPO PROMOD License for LPSC                          CUSELGLA               70,620                  -       70,620           70,620           -             -            -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP204       F3PPUD0802           ENO Integrated Resource Plan                         DIRCTENO                1,377                 84        1,461            1,461           -             -            -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP204       F5PPE14427           Regulatory Info RFIs-EAI-Dock                        DIRCTEAI                1,891                159        2,050            2,050           -             -            -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP204       F5PPZUWELL           Entergy Wellness Program                             EMPLOYAL                  439                 36           475             451          23             -            0              24

                     ENERGY AND FUEL MANAGEMENT                ESI              CP204       Total                                                                                         1,545,092             45,658    1,590,750       1,373,069      217,681             -        1,282         218,963

                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       C1PPRNE010           New Nuclear -Regulatory Fi ing                       NWDVRBGG               (1,445)              (114)     (1,559)          (1,559)           -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       C1PPSP0008           SPO ELL&ENOI Purchase Option I                       OWNISES2               (4,441)              (471)     (4,911)          (4,911)           -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       C6PCN32144           GRAND GULF EXTENDED POWER UPRA                       DIRCTSER                3,459                313       3,772            3,772            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       C6PPGN0020           New Nuclear Reg Filing EGSL On                       DIRECTLG                  723                 57         779              779            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       C6PPLN0020           New Nuclear Reg Filing ELL Ong                       DIRCTELI                  723                 57         779              779            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       C6PPRN0002           New Nuclear - Entergy                                DIRCTR1                     -                  -           -                -            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       C6PPSP0012           SPO Project Gator Transact/Tra                       DIRCTELI                2,359                179       2,537            2,537            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       C6PPSP0029           SPO Evange ine                                       DIRCTELI                  236                 20         256              256            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       C6PPSP0038           SPO Project Lamar Transaction                        DIRCTEAI                6,126                595       6,721            6,721            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       C6PPSP0046           SPO Project Burnet Transaction                       DIRCTEMI                6,719                678       7,397            7,397            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       C6PPWS0628           SPO W-WOTAB CT Development Spe                       DIRECTTX                    -                  -           -                -            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       C6PPWS0783           Ninem le 6 Development                               DIRCTELI                1,501                153       1,654            1,654            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PCCSPSYS           SYSTEM PLANNING AND STRATEGIC                        ASSTSALL                2,282                  -       2,282            2,050          232             -               -          232
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PCCSPUTI           SYSTEM PLANNING & STRATEGIC AD                       LOADOPCO              510,111             41,302     551,413          464,460       86,954             -             101       87,055
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PCF07300           CORP PLANNING & ANALYSIS- REGU                       CUSTEGOP                3,378                203       3,582            3,088          494             -               7          501
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PCF21600           CORP RPTG ANALYSIS & POLICY AL                       GENLEDAL                    -                  -           -                -            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PCFF1003           BOARD SUPPORT                                        ASSTSALL                4,920                377       5,297            4,771          526             -               9          535
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PCSYSAGR           SYSTEM AGREEMENT-2001                                CUSEOPCO                2,906                236       3,142            2,679          463             -              11          475
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PCW18300           OPNS-COAL SUPPLY                                     COALARGS                    -                  -           -                -            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PCW19510           ENERGY MANAGEMENT OPERATIONS                         LOADOPCO                    -                  -           -                -            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PCW54035           VICE PRESIDENT OF ENERGY MANAG                       LOADOPCO                   57                  -          57               48            8             -               -            8
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PCWE0058           AWARDS & RECOGNITIONS PROGRAM                        LOADOPCO                  551                 93         644              548           96             -               2           98
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PCWE0092           EMS OPERATIONS & MAINTENANCE S                       LOADOPCO                    -                  -           -                -            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PCWE0135           NEL. 6 JOINT OWNERSHIP PART. A                       DIRECTLG                  (88)                 -         (88)             (88)           -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PCWE0140           EMO REGULATORY AFFAIRS                               LOADOPCO                    -                  -           -                -            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PPADSENT           Analytic/Decision Support-Ente                       ASSTSALL                  614                  -         614              555           58             -               -           58
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PPE14434           EAI POST SYS AGMT INCREMENTAL                        DIRCTEAI                  239                 26         266              266            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PPINVDOJ           DOJ Anti Trust Investigation                         CUSEOPCO                1,961                171       2,131            1,817          314             -               6          320
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PPMSFA10           2010 EMI Fuel Audit                                  DIRCTEMI                  887                 77         964              964            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PPSPE003           SPO Summer 2009 RFP Expense                          LOADOPCO                  151                  -         151              128           23             -              (2)          21
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PPSPE011           SPO NISCO Contract                                   DIRECTLG                4,591                383       4,974            4,974            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PPSPE017           SPO 2010 Renewable RFP                               LOADOPCO                7,022                629       7,651            6,509        1,142             -              24        1,167
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PPSPE025           SPO 2010 Renewable RFP - LA on                       CUSELGLA                2,816                188       3,004            3,004            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PPSPE027           SPO ESI Project Houston PPA                          DIRCTESI                    -                  -           -                -            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PPSPE042           SPO Expense ISES Purchase Opti                       OWNISES2                9,358                869      10,227           10,227            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PPSPSENI           Strategic Planning SVCS-ENI                          DIRCTENU                  497                 39         536              536            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PPSPSENT           Strategic Planning SVCS-Enterg                       ASSTSALL               16,152              1,416      17,568           15,832        1,736             -              37        1,774
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PPSPSREG           Strategic Planning SVCS-Utilit                       ASSTSREG                5,833                459       6,292            5,352          939             -              20          960
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PPTDERSC           Entergy Regional State Committ                       LOADOPCO               27,888              2,375      30,263           25,372        4,891             -              94        4,985
9-247




                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PPTDERSD           MISO Transition ALL OPCO                             LOADOPCO                2,778                199       2,977            2,483          494             -            (494)           -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PPWE0402           SPO Regulatory Compliance                            LOADOPCO               24,145                  -      24,145           20,137        4,008             -               -        4,008
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PPWE0437           SPO Expense KGen Hinds                               DIRCTEMI                    -                  -           -                -            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PPWE0438           SPO Expense KGen Hot Springs                         DIRCTEAI                    -                  -           -                -            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PPWET300           SPO 2008 Western Region RFP-Te                       DIRECTTX                  473                 39         512                -          512             -              11          523
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PPWET302           SPO 2008 Winter Western Region                       DIRECTTX                2,630                227       2,857                -        2,857             -              55        2,912
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PPWET305           SPO WWOTAB Expense                                   DIRECTTX                    -                  -           -                -            -             -              (0)          (0)
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PPWET306           SPO 2011 Western Region RFP                          DIRECTTX                1,628                119       1,748                -        1,748             -              38        1,786
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F3PPWET308           SPO Calpine PPA/Project Housto                       DIRECTTX                2,004                176       2,180                -        2,180             -              42        2,222
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F5PCSVCAWD           SERVICE AWARDS                                       DIRCTESI                    -                  -           -                -            -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F5PCZU1425           REGULATORY COORDINAT.-ELI & EG                       CUSELPSC                  (88)                 -         (88)             (88)           -             -               -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F5PCZU1574           REGULATORY AFFAIRS - 100% TX G                       DIRECTTX                2,881                253       3,134                -        3,134             -              67        3,202

                           Amounts may not add or tie to other schedules due to rounding.
                                                                                                                                                                                                                                                                                                                  EXHIBIT PJC-C
                                                                                                                                                                                      Cicio, Patrick                                                                                                                Page 1 of 11
                                                                                                                                                                            ENTERGY TEXAS, INC.                                                                                                                         EXHIBIT PJC-C
2011 ETI Rate Case




                                                                                                                                                       Affiliate Billings - by Witness, Class, Department and Project                                                                                                2011 TX Rate Case
                                                                                                                                                                 For the Twelve Months Ended June 30, 2011                                                                                                                 Page 2 of 11
                                                                                                                                                                              Amounts in Dollars
                                                                                                                                                                                            (A)             (B)            (C)              (D)          (E)            (F)              (G)             (H)
                                                                                                                                                                                                        Total Billings
                                                                                            Activity / Project                                                          ESI BIlling                    Service Company                                  ETI Per                       Pro Forma        Total ETI
                                      Class                    Billing Entity      Dept           Code                            Activity / Project Description         Method           Support         Recipient        Total       All Other BU's   Books        Exclusions        Amount          Adjusted
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F5PCZU1579           REGULATORY AFFAIRS -- 100% EGS                       DIRECTLG                    -                  -            -                -             -             -                  -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F5PCZUDEPX           DEPRECIATION AND AMORTIZATION                        ESIDEPRE                1,450                  -        1,450            1,450             -             -                  -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F5PP10011U           Show Cause Docket No. 10-011-U                       DIRCTEAI                  986                 39        1,025            1,025             -             -                  -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F5PPETX009           2009 Texas Rate Case Support                         DIRECTTX                  473                 39          512                -           512             -               (512)             -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F5PPFALCON           Project Falcon                                       DIRECTNI                4,987                382        5,370            5,370             -             -                  -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F5PPHREXEC           HR Executive Financial Counsel                       ASSTSALL                    -                  -            -                -             -             -                  -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F5PPSPE044           PMO Support Initiative-System-                       LOADOPCO                5,279                442        5,721            4,771           950             -               (950)             -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       F5PPSUPICT           Support of ICT                                       LOADOPCO                2,576                193        2,768            2,344           425             -                  7            432

                     ENERGY AND FUEL MANAGEMENT                ESI              CP218       Total                                                                                           670,285             52,421     722,706          608,009      114,697                 -        (1,424)        113,273

                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       C1PPRNE010           New Nuclear -Regulatory Fi ing                       NWDVRBGG               (3,593)              (282)     (3,876)          (3,876)           -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       C6PCN32144           GRAND GULF EXTENDED POWER UPRA                       DIRCTSER               10,060                928      10,988           10,988            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       C6PPGN0020           New Nuclear Reg Filing EGSL On                       DIRECTLG                2,904                231       3,135            3,135            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       C6PPLN0020           New Nuclear Reg Filing ELL Ong                       DIRCTELI                2,903                231       3,135            3,135            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       C6PPN66876           Cladding Failure Root Cause &                        DIRCTWF3                5,748                545       6,293            6,293            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       C6PPRN0002           New Nuclear - Entergy                                DIRCTR1                     -                  -           -                -            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       C6PPSP0012           SPO Project Gator Transact/Tra                       DIRCTELI                1,826                175       2,001            2,001            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       C6PPSP0038           SPO Project Lamar Transaction                        DIRCTEAI                6,260                619       6,880            6,880            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       C6PPSP0046           SPO Project Burnet Transaction                       DIRCTEMI               12,482              1,158      13,640           13,640            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       C6PPWS0534           System Planning Pet Coke Repow                       DIRCTELI                  374                 11         384              384            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       C6PPWS0783           Ninem le 6 Development                               DIRCTELI               13,723              1,274      14,997           14,997            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       F3PCCSPEAI           SYSTEM PLANNING - EAI                                DIRCTEAI                8,526                729       9,255            9,255            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       F3PCCSPEEI           SYSTEM PLANNING - NONREG - EEI                       ASSTNREG                  548                 48         596              596            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       F3PCCSPELI           SYSTEM PLANNING - ELI                                DIRCTELI               26,965              2,403      29,368           29,368            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       F3PCCSPEMI           SYSTEM PLANNING - EMI                                DIRCTEMI                2,182                182       2,364            2,364            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       F3PCCSPENO           SYSTEM PLANNING - ENOI                               DIRCTENO               26,340              2,267      28,607           28,607            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       F3PCCSPGSL           SYSTEM PLANNING - EGSI-LA                            DIRECTLG               12,199              1,068      13,266           13,266            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       F3PCCSPGST           SYSTEM PLANNING - EGSI-TX                            DIRECTTX               19,618              1,785      21,402                -       21,402                 -           441          21,843
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       F3PCCSPSYS           SYSTEM PLANNING AND STRATEGIC                        ASSTSALL                1,220                 49       1,269            1,144          125                 -             1             126
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       F3PCCSPUTI           SYSTEM PLANNING & STRATEGIC AD                       LOADOPCO              740,225             60,509     800,734          674,202      126,531                 -         2,492         129,023
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       F3PCSYSRAS           SYSTEM REGULATORY AFFAIRS-STAT                       CUSTEGOP                    1                  -           1                1            0                 -             -               0
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       F3PCW15830           SYSTEM GENERATION PLANNING                           LOADOPCO                    -                  -           -                -            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       F3PPSPE003           SPO Summer 2009 RFP Expense                          LOADOPCO               28,138              2,350      30,489           25,937        4,552                 -            81           4,633
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       F3PPSPE017           SPO 2010 Renewable RFP                               LOADOPCO                1,972                314       2,286            1,945          341                 -             6             347
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       F3PPSPE025           SPO 2010 Renewable RFP - LA on                       CUSELGLA               85,008              7,809      92,817           92,817            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       F3PPSPE027           SPO ESI Project Houston PPA                          DIRCTESI                    -                  -           -                -            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       F3PPSPE042           SPO Expense ISES Purchase Opti                       OWNISES2                8,107                791       8,897            8,897            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       F3PPTDERSD           MISO Transition ALL OPCO                             LOADOPCO                2,220                168       2,388            1,992          396                 -          (396)              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       F3PPUD0802           ENO Integrated Resource Plan                         DIRCTENO                3,466                261       3,726            3,726            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       F3PPWET306           SPO 2011 Western Region RFP                          DIRECTTX               10,562                882      11,445                -       11,445                 -           250          11,695
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       F3PPWET308           SPO Calpine PPA/Project Housto                       DIRECTTX               11,630              1,095      12,726                -       12,726                 -           270          12,996
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       F5PCSVCAWD           SERVICE AWARDS                                       DIRCTESI                   89                  -          89               89            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       F5PCZCDEPT           SUPERVISION & SUPPORT - CORPOR                       LBRCORPT               15,051              1,317      16,368           15,927          441                 -            10             451

                     ENERGY AND FUEL MANAGEMENT                ESI              CP227       Total                                                                                         1,056,752             88,917    1,145,669         967,710      177,959                 -         3,154         181,114

                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       C1PCN70859           RIVER BEND EXTENDED POWER UPRA                       DIRCTEOI                    -                  -            -               -             -                -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       C1PPSP0008           SPO ELL&ENOI Purchase Option I                       OWNISES2             (103,294)            (2,027)    (105,321)       (105,321)            -                -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       C6PCN70858           RIVER BEND EXTENDED POWER UPRA                                                   -                  -            -               -             -                -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       C6PPSP0012           SPO Project Gator Transact/Tra                       DIRCTELI               33,913              2,091       36,004          36,004             -                -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       C6PPSP0038           SPO Project Lamar Transaction                        DIRCTEAI              256,430              5,319      261,749         261,749             -                -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       C6PPSP0046           SPO Project Burnet Transaction                       DIRCTEMI              309,730              5,627      315,357         315,357             -                -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       C6PPWGP516           SBC CIP Compliance                                   DIRECTTX                  120                  -          120               -           120             (120)              -              -
9-248




                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       C6PPWS0628           SPO W-WOTAB CT Development Spe                       DIRECTTX                    -                  -            -               -             -                -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       C6PPWS0783           Ninem le 6 Development                               DIRCTELI                  342                 36          378             378             -                -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PCCSPUTI           SYSTEM PLANNING & STRATEGIC AD                       LOADOPCO                  324                  -          324             271            53                -             (17)            35
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PCW18300           OPNS-COAL SUPPLY                                     COALARGS                8,363                743        9,106           9,106             -                -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PCW19512           ENERGY MGMT - FUEL & ENERGY AN                       LOADOPCO                  (47)                 -          (47)            (40)           (7)               -              (0)            (7)
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PCW29607           POWER SYSTEM ACCOUNTING                              LOADWEPI                    -                  -            -               -             -                -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PCWE0034           DIRECTOR - PLANT SUPPORT                             CAPAOPCO                    -                  -            -               -             -                -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PCWE0046           PLANT SUPPORT SERVICES - BIG C                       ASSTTXLG               15,342              1,291       16,632           9,775         6,857                -             139          6,996
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PCWE0135           NEL. 6 JOINT OWNERSHIP PART. A                       DIRECTLG                5,017                463        5,480           5,480             -                -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PPDOWPPA           Dow 3 Year PPA (2011-2014)                           DIRECTLG                  497                 52          549             549             -                -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PPE14434           EAI POST SYS AGMT INCREMENTAL                        DIRCTEAI                2,856                259        3,115           3,115             -                -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PPINVDOJ           DOJ Anti Trust Investigation                         CUSEOPCO                1,932                 82        2,014           1,717           297                -               2            299

                           Amounts may not add or tie to other schedules due to rounding.
                                                                                                                                                                                                                                                                                                                        EXHIBIT PJC-C
                                                                                                                                                                                      Cicio, Patrick                                                                                                                      Page 2 of 11
                                                                                                                                                                             ENTERGY TEXAS, INC.                                                                                                                                  EXHIBIT PJC-C
2011 ETI Rate Case




                                                                                                                                                        Affiliate Billings - by Witness, Class, Department and Project                                                                                                         2011 TX Rate Case
                                                                                                                                                                  For the Twelve Months Ended June 30, 2011                                                                                                                          Page 3 of 11
                                                                                                                                                                               Amounts in Dollars
                                                                                                                                                                                             (A)              (B)               (C)                (D)          (E)             (F)              (G)             (H)
                                                                                                                                                                                                          Total Billings
                                                                                            Activity / Project                                                           ESI BIlling                     Service Company                                       ETI Per                        Pro Forma        Total ETI
                                      Class                    Billing Entity      Dept           Code                             Activity / Project Description         Method           Support          Recipient           Total         All Other BU's   Books         Exclusions        Amount          Adjusted
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PPMSFA10           2010 EMI Fuel Audit                                   DIRCTEMI                 334                   28            362                 362           -                -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PPSPE001           SPO NISCO JOPOA MANAGEMENT EXP                        DIRECTLG                    -                   -              -                   -           -                -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PPSPE002           SPO 2009 Renewable RFI Expense                        LOADOPCO               9,446                  928         10,373               8,825       1,549                -                 32        1,581
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PPSPE003           SPO Summer 2009 RFP Expense                           LOADOPCO              35,551                3,363         38,914              33,097       5,817                -                 (3)       5,814
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PPSPE011           SPO NISCO Contract                                    DIRECTLG               1,101                   93          1,194               1,194           -                -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PPSPE015           SPO Compliance and Business Su                        LOADOPCO                    -                   -              -                   -           -                -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PPSPE017           SPO 2010 Renewable RFP                                LOADOPCO               5,690                  454          6,144               5,226         917                -                 18          935
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PPSPE025           SPO 2010 Renewable RFP - LA on                        CUSELGLA              34,620                3,254         37,874              37,874           -                -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PPSPE027           SPO ESI Project Houston PPA                           DIRCTESI                    -                   -              -                   -           -                -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PPSPE042           SPO Expense ISES Purchase Opti                        OWNISES2             138,034                2,789        140,823            140,823            -                -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PPSPE048           SPO Cottonwood Expense                                LOADOPCO                 486                   37            522                 435          87                -                  2           89
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PPTDERSC           Entergy Regional State Committ                        LOADOPCO               1,912                  176          2,088               1,744         344                -                  7          351
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PPTDERSD           MISO Transition ALL OPCO                              LOADOPCO                 959                   72          1,032                 861         171                -               (171)           -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PPWE0292           System Planning Asset Manageme                        LOADOPCO             292,780               25,337        318,116            267,550       50,566                -                878       51,444
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PPWE0420           SPO EGSL-SupplyProcuremt/Asset                        DIRECTLG               1,026                   93          1,119               1,119           -                -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PPWET302           SPO 2008 Winter Western Region                        DIRECTTX               1,286                  129          1,415                   -       1,415                -                 30        1,444
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PPWET304           SPO Frontier 10 Year PPA                              DIRECTTX                    -                   -              -                   -           -                -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PPWET305           SPO WWOTAB Expense                                    DIRECTTX                    -                   -              -                   -           -                -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PPWET306           SPO 2011 Western Region RFP                           DIRECTTX               8,778                  726          9,504                   -       9,504                -                209        9,714
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F3PPWET308           SPO Calpine PPA/Project Housto                        DIRECTTX              11,407                1,128         12,535                   -      12,535                -                266       12,801
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F5PCZU1574           REGULATORY AFFAIRS - 100% TX G                        DIRECTTX               2,264                  203          2,467                   -       2,467                -                 82        2,549
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F5PP27836P           ELI/EGS Purchase of Perryville                        DIRCTELI                   14                   -             14                  14           -                -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F5PPETX009           2009 Texas Rate Case Support                          DIRECTTX                (728)                  29           (699)                  -        (699)            (272)               971            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F5PPMSFA09           2009 EMI Fuel Audit Horne Grou                        DIRCTEMI                    -                   -              -                   -           -                -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       F5PPZUWELL           Entergy Wellness Program                              EMPLOYAL                 278                   23            301                 286          15                -                  0           15

                     ENERGY AND FUEL MANAGEMENT                ESI              CP235       Total                                                                                          1,076,761              52,798       1,129,559         1,037,552       92,007               (392)        2,445          94,059

                     ENERGY AND FUEL MANAGEMENT                ESI              CP236       F3PCCSPUTI           SYSTEM PLANNING & STRATEGIC AD                        LOADOPCO                    89                      -            89               75           14                 -                -            14

                     ENERGY AND FUEL MANAGEMENT                ESI              CP236       Total                                                                                                  89                      -            89               75           14                 -                -            14

                     ENERGY AND FUEL MANAGEMENT                ESI              CP237       C1PPSP0008           SPO ELL&ENOI Purchase Option I                        OWNISES2              (48,165)             (2,955)        (51,120)          (51,120)            -                 -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP237       C6PPSP0012           SPO Project Gator Transact/Tra                        DIRCTELI                   46                   -              46                46             -                 -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP237       F3PCWE0046           PLANT SUPPORT SERVICES - BIG C                        ASSTTXLG                   75                   -              75                43            31                 -               -             31
                     ENERGY AND FUEL MANAGEMENT                ESI              CP237       F3PCWE0135           NEL. 6 JOINT OWNERSHIP PART. A                        DIRECTLG                    -                   -               -                 -             -                 -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP237       F3PPSPE001           SPO NISCO JOPOA MANAGEMENT EXP                        DIRECTLG                    -                   -               -                 -             -                 -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP237       F3PPSPE002           SPO 2009 Renewable RFI Expense                        LOADOPCO                    -                   -               -                 -             -                 -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP237       F3PPSPE003           SPO Summer 2009 RFP Expense                           LOADOPCO                  239                   -             239               203            36                 -               -             36
                     ENERGY AND FUEL MANAGEMENT                ESI              CP237       F3PPSPE004           SPO Summer09RFP IM&PropslSubmt                        LOADOPCO                    -                   -               -                 -             -                 -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP237       F3PPSPE008           SPO July 09 Flex Baseld RFP IM                        LOADOPCO                    -                   -               -                 -             -                 -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP237       F3PPSPE010           SPO Divers ty In tiative                              LOADOPCO                    -                   -               -                 -             -                 -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP237       F3PPSPE017           SPO 2010 Renewable RFP                                LOADOPCO                  494                   -             494               421            74                 -               -             74
                     ENERGY AND FUEL MANAGEMENT                ESI              CP237       F3PPSPE042           SPO Expense ISES Purchase Opti                        OWNISES2               48,165               2,955          51,120            51,120             -                 -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP237       F3PPWE0292           System Planning Asset Manageme                        LOADOPCO                  117                   -             117                99            18                 -               -             18
                     ENERGY AND FUEL MANAGEMENT                ESI              CP237       F3PPWE0420           SPO EGSL-SupplyProcuremt/Asset                        DIRECTLG                    -                   -               -                 -             -                 -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP237       F3PPWET300           SPO 2008 Western Region RFP-Te                        DIRECTTX                    -                   -               -                 -             -                 -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP237       F3PPWET302           SPO 2008 Winter Western Region                        DIRECTTX                    -                   -               -                 -             -                 -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP237       F3PPWET304           SPO Frontier 10 Year PPA                              DIRECTTX                    -                   -               -                 -             -                 -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP237       F5PCSVCAWD           SERVICE AWARDS                                        DIRCTESI                    -                   -               -                 -             -                 -               -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP237       F5PPETX009           2009 Texas Rate Case Support                          DIRECTTX                    -                   -               -                 -             -               (30)             30              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP237       F5PPZUWELL           Entergy Wellness Program                              EMPLOYAL                    -                   -               -                 -             -                 -               -              -

                     ENERGY AND FUEL MANAGEMENT                ESI              CP237       Total                                                                                                  971                     -            971              812          159              (30)             30             159
9-249




                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       C1PPSP0008           SPO ELL&ENOI Purchase Option I                        OWNISES2              (11,335)             (1,509)        (12,844)          (12,844)              -               -                -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       C6PCN32144           GRAND GULF EXTENDED POWER UPRA                        DIRCTSER                  843                  74             918               918               -               -                -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       C6PPSP0012           SPO Project Gator Transact/Tra                        DIRCTELI                7,071                 620           7,692             7,692               -               -                -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       C6PPSP0029           SPO Evange ine                                        DIRCTELI                7,696                 653           8,348             8,348               -               -                -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       C6PPSP0030           SPO Ouachita Fuel Meter Common                        DIRCTEAI                  539                  45             584               584               -               -                -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       C6PPSP0038           SPO Project Lamar Transaction                         DIRCTEAI               33,847               3,185          37,032            37,032               -               -                -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       C6PPSP0046           SPO Project Burnet Transaction                        DIRCTEMI               34,195               3,386          37,582            37,582               -               -                -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       C6PPWS0783           Ninem le 6 Development                                DIRCTELI                  937                  96           1,033             1,033               -               -                -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       C6PPWS0984           SPO EGSL Purchase of Ouachita                         DIRECTLG                    -                   -               -                 -               -               -                -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PCCPM001           CORPORATE PERFORMANCE MANAGEME                        ASSTSALL                    -                   -               -                 -               -               -                -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PCE14420           REGULATORY AFFAIRS - EAI                              DIRCTEAI                1,293                  98           1,390             1,390               -               -                -                -

                           Amounts may not add or tie to other schedules due to rounding.
                                                                                                                                                                                                                                                                                                                                  EXHIBIT PJC-C
                                                                                                                                                                                       Cicio, Patrick                                                                                                                               Page 3 of 11
                                                                                                                                                                             ENTERGY TEXAS, INC.                                                                                                                   EXHIBIT PJC-C
2011 ETI Rate Case




                                                                                                                                                        Affiliate Billings - by Witness, Class, Department and Project                                                                                          2011 TX Rate Case
                                                                                                                                                                  For the Twelve Months Ended June 30, 2011                                                                                                           Page 4 of 11
                                                                                                                                                                               Amounts in Dollars
                                                                                                                                                                                             (A)             (B)           (C)            (D)          (E)           (F)              (G)           (H)
                                                                                                                                                                                                         Total Billings
                                                                                            Activity / Project                                                           ESI BIlling                    Service Company                               ETI Per                      Pro Forma      Total ETI
                                      Class                    Billing Entity      Dept           Code                             Activity / Project Description         Method           Support         Recipient       Total     All Other BU's   Books       Exclusions        Amount        Adjusted
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PCF07300           CORP PLANNING & ANALYSIS- REGU                        CUSTEGOP               13,590                963      14,553         12,547        2,007             -               30         2,036
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PCW15830           SYSTEM GENERATION PLANNING                            LOADOPCO                8,581                704       9,285          7,744        1,541             -               31         1,572
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PCW18300           OPNS-COAL SUPPLY                                      COALARGS                  699                 64          764           764            -             -                -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PCW19511           ENERGY MANAGEMENT OPERATIONS P                        LOADOPCO               13,071              1,208      14,279         12,040        2,239             -               43         2,283
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PCWE0046           PLANT SUPPORT SERVICES - BIG C                        ASSTTXLG                  687                 88          775           450          325             -                6           331
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PCWE0140           EMO REGULATORY AFFAIRS                                LOADOPCO                1,893                157       2,050          1,735          315             -                7           322
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPAMPDEV           Advanced Mgmt Dev Program                             EMPLOYAL                4,112                  -       4,112          3,921          192             -                -           192
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPE14434           EAI POST SYS AGMT INCREMENTAL                         DIRCTEAI                2,964                311       3,274          3,274            -             -                -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPSPE001           SPO NISCO JOPOA MANAGEMENT EXP                        DIRECTLG                2,796                229       3,026          3,026            -             -                -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPSPE002           SPO 2009 Renewable RFI Expense                        LOADOPCO                  627                 56          683           581          102             -                2           104
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPSPE003           SPO Summer 2009 RFP Expense                           LOADOPCO               22,332              2,157      24,488         20,833        3,656             -               76         3,732
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPSPE004           SPO Summer09RFP IM&PropslSubmt                        LOADOPCO              269,064                  -     269,064        227,046       42,018             -                -        42,018
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPSPE008           SPO July 09 Flex Baseld RFP IM                        LOADOPCO                    -                  -            -             -            -             -                -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPSPE010           SPO Divers ty In tiative                              LOADOPCO                1,619                140       1,759          1,483          276             -               (8)          268
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPSPE011           SPO NISCO Contract                                    DIRECTLG               15,565              1,324      16,889         16,889            -             -                -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPSPE016           Addendum-WE0418 Summer 08 IM                          LOADOPCO                    -                  -            -             -            -             -                -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPSPE017           SPO 2010 Renewable RFP                                LOADOPCO               61,600              2,221      63,820         54,293        9,528             -               82         9,610
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPSPE025           SPO 2010 Renewable RFP - LA on                        CUSELGLA             (185,612)             9,242    (176,370)      (176,370)           -             -                -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPSPE027           SPO ESI Project Houston PPA                           DIRCTESI                    -                  -            -             -            -             -                -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPSPE042           SPO Expense ISES Purchase Opti                        OWNISES2               30,539              3,149      33,688         33,688            -             -                -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPSPE049           SPO 2011 EAI RFP                                      DIRCTEAI                2,593                196       2,789          2,789            -             -                -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPTDERSC           Entergy Regional State Committ                        LOADOPCO                  508                 38          546           455           91             -                3            94
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPTDERSD           MISO Transition ALL OPCO                              LOADOPCO                   30                  -           30            25            5             -               (5)             -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPWE0403           SPO Performance Mngmnt/Special                        LOADOPCO              434,710             36,063     470,773        396,023       74,750             -           1,609         76,359
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPWET302           SPO 2008 Winter Western Region                        DIRECTTX                  303                 33          335             -          335             -                7           342
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPWET303           SPO2008WinterWestnRegionRFP-IM                        DIRECTTX                4,200                  -       4,200              -        4,200             -                -         4,200
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPWET304           SPO Frontier 10 Year PPA                              DIRECTTX                    -                  -            -             -            -             -                -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPWET306           SPO 2011 Western Region RFP                           DIRECTTX               25,766              2,245      28,011              -       28,011             -              597        28,608
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPWET307           SPO2011WestnRegionRFP-IM&PropS                        DIRECTTX               19,469                  -      19,469              -       19,469             -                -        19,469
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F3PPWET308           SPO Calpine PPA/Project Housto                        DIRECTTX               28,791              2,794      31,584              -       31,584             -              668        32,253
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F5PCSVCAWD           SERVICE AWARDS                                        DIRCTESI                    -                  -            -             -            -             -                -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F5PCZU1425           REGULATORY COORDINAT.-ELI & EG                        CUSELPSC                    -                  -            -             -            -             -                -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F5PCZU1574           REGULATORY AFFAIRS - 100% TX G                        DIRECTTX                9,627                881      10,508              -       10,508             -              223        10,731
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F5PPETX009           2009 Texas Rate Case Support                          DIRECTTX                  328                130          457             -          457          (382)             (75)             -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F5PPSPE044           PMO Support Initiative-System-                        LOADOPCO                1,403                132       1,535          1,280          255             -             (255)             -
                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       F5PPZUWELL           Entergy Wellness Program                              EMPLOYAL                1,298                 92       1,389          1,321           68             -                1            69

                     ENERGY AND FUEL MANAGEMENT                ESI              CP23K       Total                                                                                            868,238             71,263    939,501        707,570      231,931             (382)        3,043       234,592

                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       C1PPSP0008           SPO ELL&ENOI Purchase Option I                        OWNISES2               (1,901)              (196)    (2,097)        (2,097)           -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       C6PCN32144           GRAND GULF EXTENDED POWER UPRA                        DIRCTSER                  749                 65        814            814            -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       C6PCN70858           RIVER BEND EXTENDED POWER UPRA                                                3,104                283      3,386          3,386            -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       C6PPSP0012           SPO Project Gator Transact/Tra                        DIRCTELI               84,812                209     85,022         85,022            -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       C6PPSP0038           SPO Project Lamar Transaction                         DIRCTEAI               58,180                443     58,622         58,622            -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       C6PPSP0046           SPO Project Burnet Transaction                        DIRCTEMI               47,758                 69     47,827         47,827            -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       C6PPWS0628           SPO W-WOTAB CT Development Spe                        DIRECTTX                    -                  -          -              -            -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       C6PPWS0783           Ninem le 6 Development                                DIRCTELI                3,133                191      3,324          3,324            -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PCCSPSYS           SYSTEM PLANNING AND STRATEGIC                         ASSTSALL               28,841                325     29,166         26,223        2,943                -             8          2,951
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PCCSPUTI           SYSTEM PLANNING & STRATEGIC AD                        LOADOPCO              335,569             24,721    360,290        303,252       57,038                -         1,245         58,283
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PCFBLETR           BELOW THE LINE EXPENSES -ETR                          DIRCTETR                    -                  -          -              -            -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PCW54035           VICE PRESIDENT OF ENERGY MANAG                        LOADOPCO                    -                  -          -              -            -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PPAMPDEV           Advanced Mgmt Dev Program                             EMPLOYAL                    -                  -          -              -            -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PPISP717           Integration Planning Studies 7                        LOADOPCO               23,997              2,510     26,507         22,313        4,193                -            86          4,279
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PPSPE003           SPO Summer 2009 RFP Expense                           LOADOPCO               18,973              1,594     20,567         17,294        3,274                -            71          3,344
9-250




                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PPSPE017           SPO 2010 Renewable RFP                                LOADOPCO                2,666                218      2,883          2,453          430                -             9            440
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PPSPE024           SPO Power Delivery & Tech Serv                        LOADOPCO              347,682             30,035    377,718        318,197       59,520                -         1,127         60,648
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PPSPE025           SPO 2010 Renewable RFP - LA on                        CUSELGLA               17,258              1,407     18,665         18,665            -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PPSPE027           SPO ESI Project Houston PPA                           DIRCTESI                    -                  -          -              -            -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PPSPE042           SPO Expense ISES Purchase Opti                        OWNISES2                1,901                196      2,097          2,097            -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PPSPE045           PMO Support Initiative - EAI                          DIRCTEAI                2,817                234      3,051          3,051            -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PPSPE049           SPO 2011 EAI RFP                                      DIRCTEAI                  758                  -        758            758            -                -             -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PPTCGS11           TX Docket Competitive Generati                        DIRECTTX                2,786                259      3,046              -        3,046                -            64          3,110
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PPTDERSC           Entergy Regional State Committ                        LOADOPCO               18,139              1,368     19,507         16,276        3,231                -            59          3,290
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PPTDERSD           MISO Transition ALL OPCO                              LOADOPCO                4,880                369      5,249          4,378          871                -          (871)             -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PPWE0292           System Planning Asset Manageme                        LOADOPCO                5,502                  -      5,502          4,627          876                -             -            876
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PPWET301           SPO ETI-SupplyProcuremt/AssetM                        DIRECTTX                    -                  -          -              -            -                -             -              -

                           Amounts may not add or tie to other schedules due to rounding.
                                                                                                                                                                                                                                                                                                                   EXHIBIT PJC-C
                                                                                                                                                                                       Cicio, Patrick                                                                                                                Page 4 of 11
                                                                                                                                                                             ENTERGY TEXAS, INC.                                                                                                                        EXHIBIT PJC-C
2011 ETI Rate Case




                                                                                                                                                        Affiliate Billings - by Witness, Class, Department and Project                                                                                               2011 TX Rate Case
                                                                                                                                                                  For the Twelve Months Ended June 30, 2011                                                                                                                Page 5 of 11
                                                                                                                                                                               Amounts in Dollars
                                                                                                                                                                                             (A)             (B)            (C)             (D)          (E)            (F)              (G)             (H)
                                                                                                                                                                                                         Total Billings
                                                                                            Activity / Project                                                           ESI BIlling                    Service Company                                 ETI Per                       Pro Forma        Total ETI
                                      Class                    Billing Entity     Dept            Code                             Activity / Project Description         Method           Support         Recipient        Total      All Other BU's   Books        Exclusions        Amount          Adjusted
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PPWET302           SPO 2008 Winter Western Region                        DIRECTTX                    -                  -           -                -           -               -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PPWET304           SPO Frontier 10 Year PPA                              DIRECTTX                    -                  -           -                -           -               -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PPWET305           SPO WWOTAB Expense                                    DIRECTTX                    -                  -           -                -           -               -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PPWET306           SPO 2011 Western Region RFP                           DIRECTTX               37,953              1,440      39,394                -      39,394               -                408       39,802
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F3PPWET308           SPO Calpine PPA/Project Housto                        DIRECTTX                  612                 61         673                -         673               -                 14          688
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F5PCSVCAWD           SERVICE AWARDS                                        DIRCTESI                   65                  -          65               65           -               -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F5PPBULKPW           Minimize of Bulk Power Supply                         LOADOPCO               10,688                868      11,556            9,638       1,918               -                 39        1,957
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F5PPSPE044           PMO Support Initiative-System-                        LOADOPCO                5,161                455       5,615            4,683         932               -               (932)           -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       F5PPZUWELL           Entergy Wellness Program                              EMPLOYAL                  319                 26         344              327          17               -                  0           17

                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLG       Total                                                                                          1,062,402             67,150    1,129,552        951,196      178,356                 -         1,328         179,684

                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLQ       C1PPSP0008           SPO ELL&ENOI Purchase Option I                        OWNISES2               (4,709)              (485)     (5,194)         (5,194)            -                -             -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLQ       C6PPSP0038           SPO Project Lamar Transaction                         DIRCTEAI                4,635                346       4,981           4,981             -                -             -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLQ       C6PPSP0046           SPO Project Burnet Transaction                        DIRCTEMI                2,460                245       2,704           2,704             -                -             -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLQ       F3PCW18300           OPNS-COAL SUPPLY                                      COALARGS              761,242             65,256     826,498         826,498             -                -             -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLQ       F3PCWE0046           PLANT SUPPORT SERVICES - BIG C                        ASSTTXLG               12,126                969      13,095           7,700         5,395                -           109            5,504
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLQ       F3PPSPE006           SPO ISES Mining Asset Evaluati                        DIRCTEAI                    -                  -           -               -             -                -             -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLQ       F3PPSPE011           SPO NISCO Contract                                    DIRECTLG                   50                  -          50              50             -                -             -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLQ       F3PPSPE017           SPO 2010 Renewable RFP                                LOADOPCO                  (78)                 -         (78)            (67)          (12)               -            (0)             (12)
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLQ       F3PPSPE025           SPO 2010 Renewable RFP - LA on                        CUSELGLA                3,697                373       4,071           4,071             -                -             -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLQ       F3PPSPE042           SPO Expense ISES Purchase Opti                        OWNISES2                4,810                493       5,303           5,303             -                -             -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLQ       F3PPWE0292           System Planning Asset Manageme                        LOADOPCO               21,464              1,948      23,412          19,566         3,846                -            74            3,920
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLQ       F5PPETX009           2009 Texas Rate Case Support                          DIRECTTX                2,042                327       2,369               -         2,369             (923)       (1,446)               -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLQ       F5PPPAPDIS           Paper Barrier Case                                    DIRCTEAI                    -                  -           -               -             -                -             -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLQ       F5PPWE0485           2010 EPA Request for Informati                        CAPAOPCO                   45                  4          48              43             5                -             0                5
                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLQ       F5PPZUWELL           Entergy Wellness Program                              EMPLOYAL                  439                 36         475             451            23                -             0               24

                     ENERGY AND FUEL MANAGEMENT                ESI              CPSLQ       Total                                                                                            808,223             69,511     877,734         866,107       11,627              (923)       (1,263)           9,442

                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       C1PPRNE010           New Nuclear -Regulatory Fi ing                        NWDVRBGG               (4,804)              (378)     (5,182)         (5,182)           -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       C1PPSP0008           SPO ELL&ENOI Purchase Option I                        OWNISES2                 (105)               (40)       (145)           (145)           -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       C6PPGN0020           New Nuclear Reg Filing EGSL On                        DIRECTLG                2,402                189       2,591           2,591            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       C6PPLN0020           New Nuclear Reg Filing ELL Ong                        DIRCTELI                3,041                241       3,282           3,282            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       C6PPMN0020           New Nuclear Reg Filing EMI Ong                        DIRCTEMI                    -                  -           -               -            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       C6PPRN0010           New Nuclear - Regulatory Fi in                        DIRCTR1                     -                  -           -               -            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       C6PPSP0012           SPO Project Gator Transact/Tra                        DIRCTELI                7,328                660       7,988           7,988            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       C6PPWS0534           System Planning Pet Coke Repow                        DIRCTELI                    -                  -           -               -            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       C6PPWS0783           Ninem le 6 Development                                DIRCTELI                  217                 23         240             240            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PCE14420           REGULATORY AFFAIRS - EAI                              DIRCTEAI               15,842              1,373      17,216          17,216            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PCE14423           REGULATORY AFFAIRS - EMI                              DIRCTEMI                7,187                678       7,865           7,865            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PCFF1003           BOARD SUPPORT                                         ASSTSALL                  514                  -         514             462           52                 -            (0)             52
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PCSYSAGR           SYSTEM AGREEMENT-2001                                 CUSEOPCO              252,418             20,096     272,514         232,235       40,279                 -         1,118          41,397
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PCSYSRAS           SYSTEM REGULATORY AFFAIRS-STAT                        CUSTEGOP                2,615                257       2,871           2,473          398                 -            13             411
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PCW15822           RESOURCE PLANNING COORDINATOR                         LOADOPCO              122,890             11,496     134,385         113,301       21,085                 -           694          21,779
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PCW19501           WHOLESALE PURCHASING & SALES                          LOADOPCO               50,737             (9,302)     41,435          34,558        6,878                 -           236           7,114
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PCW19512           ENERGY MGMT - FUEL & ENERGY AN                        LOADOPCO                3,049                  -       3,049           2,574          474                 -             -             474
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PCWE0058           AWARDS & RECOGNITIONS PROGRAM                         LOADOPCO                    -                  -           -               -            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PCWE0140           EMO REGULATORY AFFAIRS                                LOADOPCO              444,824             40,418     485,242         409,175       76,067                 -         1,855          77,923
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PCZU1571           EGSI TX FUEL RELATED MATTERS                          DIRECTTX                   67                  -          67               -           67                 -             -              67
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PPADTFL9           ELL Fuel Audit 2005-2009                              DIRCTELI                1,541                141       1,682           1,682            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PPDOWPPA           Dow 3 Year PPA (2011-2014)                            DIRECTLG                1,125                 99       1,224           1,224            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PPEAIMIS           MISO Transition EAI Path 1 cos                        DIRCTEAI                4,725                357       5,082           5,082            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PPEMI381           EMI-2010 PMR Docket 2008-UN-38                        DIRCTEMI                1,048                109       1,157           1,157            -                 -             -               -
9-251




                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PPEMI884           EMI-2010 ECR Docket 2008-UN-88                        DIRCTEMI                1,058                108       1,166           1,166            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PPINVDOJ           DOJ Anti Trust Investigation                          CUSEOPCO               11,929              1,107      13,036          11,111        1,925                 -            64           1,989
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PPMSEE10           MS Docket2010-AD-02 Ergy Effic                        DIRCTEMI                    -                  -           -               -            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PPMSFA10           2010 EMI Fuel Audit                                   DIRCTEMI                4,023                359       4,382           4,382            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PPPGA010           PGA Audit 2010                                        DIRECTLG                3,163                301       3,463           3,463            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PPR56620           WHOLESALE - EGSI LA                                   DIRECTLG                    -                  -           -               -            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PPSPE010           SPO Divers ty In tiative                              LOADOPCO                  396                 39         435             366           69                 -             1              70
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PPSPE011           SPO NISCO Contract                                    DIRECTLG                2,171                171       2,342           2,342            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PPSPE042           SPO Expense ISES Purchase Opti                        OWNISES2                1,993                201       2,195           2,195            -                 -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PPTDERSC           Entergy Regional State Committ                        LOADOPCO              108,613              7,240     115,852          97,008       18,845                 -           435          19,279
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PPTDERSD           MISO Transition ALL OPCO                              LOADOPCO               18,016              1,003      19,019          15,862        3,157                 -        (3,157)              -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F3PPWE0432           SPOManagement of Sys IRP Activ                        LOADOPCO                1,286                107       1,393           1,177          216                 -             7             223

                           Amounts may not add or tie to other schedules due to rounding.
                                                                                                                                                                                                                                                                                                                        EXHIBIT PJC-C
                                                                                                                                                                                       Cicio, Patrick                                                                                                                     Page 5 of 11
                                                                                                                                                                             ENTERGY TEXAS, INC.                                                                                                                      EXHIBIT PJC-C
2011 ETI Rate Case




                                                                                                                                                        Affiliate Billings - by Witness, Class, Department and Project                                                                                             2011 TX Rate Case
                                                                                                                                                                  For the Twelve Months Ended June 30, 2011                                                                                                              Page 6 of 11
                                                                                                                                                                               Amounts in Dollars
                                                                                                                                                                                             (A)             (B)           (C)              (D)          (E)           (F)              (G)             (H)
                                                                                                                                                                                                         Total Billings
                                                                                            Activity / Project                                                           ESI BIlling                    Service Company                                 ETI Per                      Pro Forma        Total ETI
                                      Class                    Billing Entity      Dept           Code                             Activity / Project Description         Method           Support         Recipient       Total       All Other BU's   Books       Exclusions        Amount          Adjusted
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PC25116F           ELI FUEL AUDIT 2001                                   DIRCTELI               1,394                 117       1,511            1,511           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PCE13751           GENERAL LITIGATION- EGSI-LA                           DIRECTLG               4,125                 364       4,489            4,489           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PCE13759           JENKINS CLASS ACTION SUIT                             DIRECTTX              23,848               2,024     25,872                 -      25,872              -             773          26,645
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PCEDIVER           DIVERSITY TRAINING                                    DIRCTESI                   45                  -           45              45           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PCGSL351           ELI 2001 SYSTEM AGREEMENT CASE                        DIRCTELI               1,234                 125       1,359            1,359           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PCGSL500           EGS FUEL AUDIT                                        DIRECTLG               1,794                 102       1,896            1,896           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PCSVCAWD           SERVICE AWARDS                                        DIRCTESI                 675                   -          675             675           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PCZU1422           REGULATORY AFFAIRS - LP&L                             DIRCTELI               8,668                 829       9,498            9,498           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PCZU1424           REGULATORY AFFAIRS - NOPSI                            DIRCTENO              35,320               3,047     38,366            38,366           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PCZU1425           REGULATORY COORDINAT.-ELI & EG                        CUSELPSC                 654                  58          712             712           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PCZU1573           REGULATORY AFFAIRS -- 100% EGS                        DIRECTTX                    -                  -            -               -           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PCZU1574           REGULATORY AFFAIRS - 100% TX G                        DIRECTTX               1,596                 145       1,741                -       1,741              -              58           1,799
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PCZU1579           REGULATORY AFFAIRS -- 100% EGS                        DIRECTLG               2,045                 185       2,230            2,230           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PP10011U           Show Cause Docket No. 10-011-U                        DIRCTEAI              65,919               5,576     71,495            71,495           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PP4RFERC           FERC Audit                                            LVLSVCAL               1,999                 187       2,185            1,975         210              -               7             217
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PPE14427           Regulatory Info RFIs-EAI-Dock                         DIRCTEAI               4,227                 383       4,610            4,610           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PPETX009           2009 Texas Rate Case Support                          DIRECTTX               5,001                 437       5,439                -       5,439           (812)         (4,626)              -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PPETX011           2011 Texas Rate Case Support                          DIRECTTX                 222                  25          247               -         247              -               8             255
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PPLEGRB3           Regulatory Filings - River Ben                        CUSELGLA                 176                   -          176             176           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PPMSFA09           2009 EMI Fuel Audit Horne Grou                        DIRCTEMI                 648                  54          702             702           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PPMSFA9A           2009 EMI Fuel Audit McFadden G                        DIRCTEMI                    -                  -            -               -           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PPSPE044           PMO Support Initiative-System-                        LOADOPCO                 142                   -          142             118          24              -             (24)              -
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PPSUPICT           Support of ICT                                        LOADOPCO               8,380                 535       8,915            7,531       1,384              -              30           1,414
                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       F5PPZUWELL           Entergy Wellness Program                              EMPLOYAL               1,138                  78       1,216            1,157          59              -               1              61

                     ENERGY AND FUEL MANAGEMENT                ESI              SE08B       Total                                                                                          1,238,559             91,322   1,329,881       1,125,393      204,488             (812)       (2,507)        201,168

                     ENERGY AND FUEL MANAGEMENT                ESI              SESEE       F3PCCSPUTI           SYSTEM PLANNING & STRATEGIC AD                        LOADOPCO                  343                 38        381              318           63                -             1              65
                     ENERGY AND FUEL MANAGEMENT                ESI              SESEE       F3PCWE0046           PLANT SUPPORT SERVICES - BIG C                        ASSTTXLG                  798                 60        858              511          347                -             7             354
                     ENERGY AND FUEL MANAGEMENT                ESI              SESEE       F3PCWE0058           AWARDS & RECOGNITIONS PROGRAM                         LOADOPCO                  797                108        905              770          135                -             3             138
                     ENERGY AND FUEL MANAGEMENT                ESI              SESEE       F3PCWE0140           EMO REGULATORY AFFAIRS                                LOADOPCO                  303                  -        303              254           48                -             -              48
                     ENERGY AND FUEL MANAGEMENT                ESI              SESEE       F3PPE14434           EAI POST SYS AGMT INCREMENTAL                         DIRCTEAI                2,772                210      2,982            2,982            -                -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESEE       F3PPSPE003           SPO Summer 2009 RFP Expense                           LOADOPCO                  (28)                12        (16)             (14)          (2)               -            (0)             (3)
                     ENERGY AND FUEL MANAGEMENT                ESI              SESEE       F3PPSPE015           SPO Compliance and Business Su                        LOADOPCO               38,521              3,536     42,057           35,327        6,730                -           131           6,861
                     ENERGY AND FUEL MANAGEMENT                ESI              SESEE       F3PPSPE025           SPO 2010 Renewable RFP - LA on                        CUSELGLA                  399                 34        433              433            -                -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESEE       F3PPTDERSD           MISO Transition ALL OPCO                              LOADOPCO                  980                 76      1,056              881          175                -          (175)              -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESEE       F3PPWE0402           SPO Regulatory Compliance                             LOADOPCO              521,697             47,326    569,024          479,121       89,902                -         1,882          91,784
                     ENERGY AND FUEL MANAGEMENT                ESI              SESEE       F5PCSVCAWD           SERVICE AWARDS                                        DIRCTESI                    -                  -          -                -            -                -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESEE       F5PPETX009           2009 Texas Rate Case Support                          DIRECTTX                  471                 37        508                -          508              (51)         (457)              -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESEE       F5PPFERCCM           FERC Compliance Program                               EMPLOREG                   67                  -         67               63            4                -             -               4
                     ENERGY AND FUEL MANAGEMENT                ESI              SESEE       F5PPZUWELL           Entergy Wellness Program                              EMPLOYAL                  527                 34        561              534           27                -             1              28

                     ENERGY AND FUEL MANAGEMENT                ESI              SESEE       Total                                                                                            567,647             51,472    619,119          521,181       97,938              (51)        1,392          99,280

                     ENERGY AND FUEL MANAGEMENT                ESI              SESKA       F3PCW15830           SYSTEM GENERATION PLANNING                            LOADOPCO                    9                  -           9               7            1                -                -            1
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKA       F3PCW19512           ENERGY MGMT - FUEL & ENERGY AN                        LOADOPCO                    4                  -           4               4            1                -                -            1
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKA       F3PCW54035           VICE PRESIDENT OF ENERGY MANAG                        LOADOPCO            1,067,079                310   1,067,389         900,287      167,103                -                8      167,111
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKA       F3PCWE0058           AWARDS & RECOGNITIONS PROGRAM                         LOADOPCO                9,047              1,241      10,288           8,732        1,556                -               33        1,589
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKA       F3PPSPE010           SPO Divers ty In tiative                              LOADOPCO                  604                  -         604             510           94                -                -           94
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKA       F3PPWE0478           Parkwood II Safety Team                               CAPAOPCO                8,234                  -       8,234           7,343          890                -             (147)         743

                     ENERGY AND FUEL MANAGEMENT                ESI              SESKA       Total                                                                                          1,084,977              1,551   1,086,528         916,884      169,644                -             (106)     169,538

                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       C6PPLN0020           New Nuclear Reg Filing ELL Ong                        DIRCTELI                1,371                105       1,477           1,477            -                -             -               -
9-252




                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F3PCSYSAGR           SYSTEM AGREEMENT-2001                                 CUSEOPCO                5,642              1,001       6,643           5,664          979                -            25           1,004
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F3PCSYSRAS           SYSTEM REGULATORY AFFAIRS-STAT                        CUSTEGOP                   76                  8          84              72           12                -             0              12
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F3PCW15830           SYSTEM GENERATION PLANNING                            LOADOPCO                   18                  -          18              16            3                -             -               3
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F3PCW18200           OPNS-OIL SUPPLY                                       OWNISFI                 3,198                318       3,516           3,516            -                -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F3PCW19501           WHOLESALE PURCHASING & SALES                          LOADOPCO                    -                  -           -               -            -                -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F3PCW19512           ENERGY MGMT - FUEL & ENERGY AN                        LOADOPCO            1,012,944             90,454   1,103,399         929,008      174,390                -         3,337         177,727
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F3PCW29607           POWER SYSTEM ACCOUNTING                               LOADWEPI              420,638             38,815     459,453         387,423       72,031                -         1,389          73,419
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F3PCWE0064           LONG TERM ENERGY                                      LOADOPCO                1,228                  -       1,228           1,038          190                -             -             190
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F3PCWE0151           FOSSIL DIVERSITY INITIATIVE -                         CAPAOPCO                   68                  5          73              65            8                -             0               8
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F3PCZU1582           EGSI LA 3RD EARNINGS REVIEW                           DIRECTLG                  (43)                 -         (43)            (43)           -                -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F3PPAMPDEV           Advanced Mgmt Dev Program                             EMPLOYAL                6,037                  -       6,037           5,747          289                -             -             289
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F3PPEAIMIS           MISO Transition EAI Path 1 cos                        DIRCTEAI                3,214                243       3,457           3,457            -                -             -               -

                           Amounts may not add or tie to other schedules due to rounding.
                                                                                                                                                                                                                                                                                                                      EXHIBIT PJC-C
                                                                                                                                                                                       Cicio, Patrick                                                                                                                   Page 6 of 11
                                                                                                                                                                             ENTERGY TEXAS, INC.                                                                                                                                   EXHIBIT PJC-C
2011 ETI Rate Case




                                                                                                                                                        Affiliate Billings - by Witness, Class, Department and Project                                                                                                          2011 TX Rate Case
                                                                                                                                                                  For the Twelve Months Ended June 30, 2011                                                                                                                           Page 7 of 11
                                                                                                                                                                               Amounts in Dollars
                                                                                                                                                                                             (A)               (B)               (C)               (D)           (E)             (F)              (G)             (H)
                                                                                                                                                                                                           Total Billings
                                                                                            Activity / Project                                                           ESI BIlling                      Service Company                                       ETI Per                        Pro Forma        Total ETI
                                      Class                    Billing Entity      Dept           Code                             Activity / Project Description         Method           Support           Recipient           Total        All Other BU's    Books         Exclusions        Amount          Adjusted
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F3PPMSFA10           2010 EMI Fuel Audit                                   DIRCTEMI              20,663                 2,060         22,723             22,723            -                -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F5PCE13759           JENKINS CLASS ACTION SUIT                             DIRECTTX               9,520                   851         10,371                  -       10,371                -                203       10,574
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F5PCEDIVER           DIVERSITY TRAINING                                    DIRCTESI                   45                    -               45               45            -                -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F5PCSVCAWD           SERVICE AWARDS                                        DIRCTESI                 336                     -              336              336            -                -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F5PCZU1422           REGULATORY AFFAIRS - LP&L                             DIRCTELI               1,408                   156           1,564             1,564            -                -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F5PCZU1579           REGULATORY AFFAIRS -- 100% EGS                        DIRECTLG               3,000                   255           3,255             3,255            -                -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F5PP10011U           Show Cause Docket No. 10-011-U                        DIRCTEAI              29,566                 2,744         32,310             32,310            -                -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F5PP4RFERC           FERC Audit                                            LVLSVCAL                    -                    -                -                -            -                -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F5PPMSFA09           2009 EMI Fuel Audit Horne Grou                        DIRCTEMI                 465                    44              508              508            -                -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F5PPMSFA9A           2009 EMI Fuel Audit McFadden G                        DIRCTEMI                 518                    57              575              575            -                -                  -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F5PPSPE044           PMO Support Initiative-System-                        LOADOPCO               4,691                   422           5,113             4,264          849                -               (849)           -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       F5PPZUWELL           Entergy Wellness Program                              EMPLOYAL                 439                    36              475              451           23                -                  0           24

                     ENERGY AND FUEL MANAGEMENT                ESI              SESKB       Total                                                                                          1,525,041             137,574        1,662,615        1,403,471       259,144                  -         4,105         263,250

                     ENERGY AND FUEL MANAGEMENT                ESI              SESKC       C1PPSP0008           SPO ELL&ENOI Purchase Option I                        OWNISES2                    (22)                     -          (22)              (22)             -               -                -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKC       F3PCW18300           OPNS-COAL SUPPLY                                      COALARGS                    491                      -          491               491              -               -                -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKC       F3PPSPE042           SPO Expense ISES Purchase Opti                        OWNISES2                     22                      -           22                22              -               -                -                -

                     ENERGY AND FUEL MANAGEMENT                ESI              SESKC       Total                                                                                                  491                      -          491               491              -               -                -                -

                     ENERGY AND FUEL MANAGEMENT                ESI              SESKD       C6PPSP0012           SPO Project Gator Transact/Tra                        DIRCTELI                  114                   10             124              124             -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKD       C6PPSP0029           SPO Evange ine                                        DIRCTELI               26,099                1,749          27,848           27,848             -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKD       C6PPSP0038           SPO Project Lamar Transaction                         DIRCTEAI                7,009                    5           7,013            7,013             -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKD       C6PPSP0046           SPO Project Burnet Transaction                        DIRCTEMI                   56                    5              61               61             -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKD       C6PPWS0783           Ninem le 6 Development                                DIRCTELI                  171                   18             189              189             -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKD       F3PCFBLFOS           BELOW THE LINE - FOSSIL OPERAT                        CAPAOPCO                3,684                    -           3,684            3,286           398               (398)            -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKD       F3PCFVARAS           ADMIN SUPRT - VARIBUS CORPORAT                        DIRECTLG               40,766                3,739          44,505           44,505             -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKD       F3PCW18100           OPNS-GAS SUPPLY                                       CAPXCOPC              984,445               88,994       1,073,438          926,742       146,696                  -         2,795         149,491
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKD       F3PCW18200           OPNS-OIL SUPPLY                                       OWNISFI               133,587               12,416         146,004          146,004             -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKD       F3PCW19512           ENERGY MGMT - FUEL & ENERGY AN                        LOADOPCO                    -                    -               -                -             -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKD       F3PCW51400           SFI FUEL OIL O&M                                      DIRCTSFI                  108                   11             119              119             -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKD       F3PCW54035           VICE PRESIDENT OF ENERGY MANAG                        LOADOPCO                   83                    -              83               71            12                  -             -              12
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKD       F3PCWE0012           1998 FUELS MANAGEMENT TELEMETR                        CAPAOPCO              140,071                    -         140,071          124,928        15,143                  -             -          15,143
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKD       F3PPUTLDER           Utility Derivatives Compliance                        LOADOPCO                2,881                  261           3,142            2,620           521                  -            11             533
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKD       F5PCZU1422           REGULATORY AFFAIRS - LP&L                             DIRCTELI                  (83)                   -             (83)             (83)            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKD       F5PPETX009           2009 Texas Rate Case Support                          DIRECTTX                 (580)                  30            (550)               -          (550)              (183)          733               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKD       F5PPZUWELL           Entergy Wellness Program                              EMPLOYAL                   23                    1              24               23             1                  -             0               1

                     ENERGY AND FUEL MANAGEMENT                ESI              SESKD       Total                                                                                          1,338,433             107,239        1,445,672        1,283,449       162,223               (581)        3,539         165,181

                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       C1PPRTOSOF           RTO Implement Software ALLCOS                         LOADOPCO               13,959                1,480         15,439            12,876         2,563          (2,563)               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       C6PPSP0045           SPO Real Time Calcasieu RTU                           DIRECTLG               25,835                  156         25,991            25,991             -               -                -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       C6PPWS0783           Ninem le 6 Development                                DIRCTELI                2,572                  273          2,845             2,845             -               -                -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F3PCWE0046           PLANT SUPPORT SERVICES - BIG C                        ASSTTXLG                  459                   48            507               294           214               -                4             218
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F3PCWE0058           AWARDS & RECOGNITIONS PROGRAM                         LOADOPCO                  319                   40            359               305            54               -                1              55
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F3PCWE0092           EMS OPERATIONS & MAINTENANCE S                        LOADOPCO               89,299                    -         89,299            74,476        14,823               -              279          15,102
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F3PCWE0133           EMO INFORMATION TECHNOLOGY SUP                        LOADOPCO                7,521                    -          7,521             6,273         1,248               -                -           1,248
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F3PPEGSLMI           MISO Transition EGSL costs                            DIRECTLG                  235                    -            235               235             -               -                -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F3PPELLMIS           MISO Transition ELL costs                             DIRCTELI                  235                    -            235               235             -               -                -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F3PPINVDOJ           DOJ Anti Trust Investigation                          CUSEOPCO                   74                    -             74                63            11               -                -              11
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F3PPSPE001           SPO NISCO JOPOA MANAGEMENT EXP                        DIRECTLG                 (449)                   -           (449)             (449)            -               -                -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F3PPSPE010           SPO Divers ty In tiative                              LOADOPCO                  804                    -            804               671           134               -                -             134
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F3PPSPE015           SPO Compliance and Business Su                        LOADOPCO              821,572               74,551        896,124           754,239       141,884               -            2,518         144,402
9-253




                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F3PPSPE019           SPO IT Infrastructure Maint.                          LOADOPCO              100,713                    -        100,713            83,996        16,718               -                -          16,718
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F3PPSPE020           SPO SOFTWARE SUPPORT/LICENSING                        LOADOPCO               24,665                    -         24,665            20,571         4,094               -                -           4,094
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F3PPSPE022           SPO Communications Infrastruct                        LOADOPCO               52,135                    -         52,135            43,481         8,654               -                -           8,654
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F3PPSPE024           SPO Power Delivery & Tech Serv                        LOADOPCO                  125                   12            137               114            23               -                0              23
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F3PPSPE028           SPO CIP Expense                                       LOADOPCO               85,786                    -         85,786            71,547        14,240               -                -          14,240
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F3PPSPE038           SPO Pwr Del & Tech Svcs - EMI                         DIRCTEMI                    -                    -              -                 -             -               -                -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F3PPSPE042           SPO Expense ISES Purchase Opti                        OWNISES2                1,286                  113          1,399             1,399             -               -                -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F3PPSPE047           SPO Telecommunications                                LOADOPCO                6,086                    -          6,086             5,075         1,010               -                -           1,010
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F3PPTDERSC           Entergy Regional State Committ                        LOADOPCO                2,288                  179          2,466             2,057           409               -                9             419
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F3PPTDERSD           MISO Transition ALL OPCO                              LOADOPCO                2,217                  167          2,384             1,989           396               -             (396)              -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F3PPWET304           SPO Frontier 10 Year PPA                              DIRECTTX                    -                    -              -                 -             -               -                -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F5PCE13611           GENERAL LITIGATION-ENOI                               DIRCTENO                2,733                  257          2,990             2,990             -               -                -               -

                           Amounts may not add or tie to other schedules due to rounding.
                                                                                                                                                                                                                                                                                                                                   EXHIBIT PJC-C
                                                                                                                                                                                       Cicio, Patrick                                                                                                                                Page 7 of 11
                                                                                                                                                                             ENTERGY TEXAS, INC.                                                                                                                                  EXHIBIT PJC-C
2011 ETI Rate Case




                                                                                                                                                        Affiliate Billings - by Witness, Class, Department and Project                                                                                                         2011 TX Rate Case
                                                                                                                                                                  For the Twelve Months Ended June 30, 2011                                                                                                                          Page 8 of 11
                                                                                                                                                                               Amounts in Dollars
                                                                                                                                                                                             (A)              (B)               (C)                (D)          (E)             (F)              (G)             (H)
                                                                                                                                                                                                          Total Billings
                                                                                            Activity / Project                                                           ESI BIlling                     Service Company                                       ETI Per                        Pro Forma        Total ETI
                                      Class                    Billing Entity      Dept           Code                             Activity / Project Description         Method           Support          Recipient           Total         All Other BU's   Books         Exclusions        Amount          Adjusted
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F5PCE13751           GENERAL LITIGATION- EGSI-LA                           DIRECTLG                 274                   24             297                297             -              -                  -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F5PCEDIVER           DIVERSITY TRAINING                                    DIRCTESI                   45                   -              45                 45             -              -                  -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F5PCSVCAWD           SERVICE AWARDS                                        DIRCTESI                 412                    -             412                412             -              -                  -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F5PCZU1574           REGULATORY AFFAIRS - 100% TX G                        DIRECTTX                 161                   14             175                  -           175              -                  4            179
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F5PP10011U           Show Cause Docket No. 10-011-U                        DIRCTEAI               2,917                  287           3,204              3,204             -              -                  -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F5PPSPE044           PMO Support Initiative-System-                        LOADOPCO               1,681                    -           1,681              1,402           279              -               (279)             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F5PPSUPICT           Support of ICT                                        LOADOPCO               3,501                  344           3,845              3,206           638              -                 21            659
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       F5PPZUWELL           Entergy Wellness Program                              EMPLOYAL               1,104                   87           1,190              1,132            58              -                  1             60

                     ENERGY AND FUEL MANAGEMENT                ESI              SESKE       Total                                                                                          1,250,562              78,031       1,328,594         1,120,970      207,624          (2,563)           2,163         207,224

                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       C1PPSP0008           SPO ELL&ENOI Purchase Option I                        OWNISES2                    0                  (5)            (5)                (5)           -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       C6PCN32144           GRAND GULF EXTENDED POWER UPRA                        DIRCTSER                  816                  77            893                893            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       C6PPGN0020           New Nuclear Reg Filing EGSL On                        DIRECTLG                  324                  25            349                349            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       C6PPLN0020           New Nuclear Reg Filing ELL Ong                        DIRCTELI                  324                  25            349                349            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       C6PPSP0012           SPO Project Gator Transact/Tra                        DIRCTELI                  725                  66            791                791            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       C6PPSP0038           SPO Project Lamar Transaction                         DIRCTEAI                    2                   0              2                  2            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       C6PPSP0046           SPO Project Burnet Transaction                        DIRCTEMI                    2                   0              2                  2            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       C6PPWS0783           Ninem le 6 Development                                DIRCTELI                3,543                 329          3,872              3,872            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PCCSPEAI           SYSTEM PLANNING - EAI                                 DIRCTEAI                  568                  47            616                616            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PCCSPELI           SYSTEM PLANNING - ELI                                 DIRCTELI                1,088                 106          1,194              1,194            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PCCSPENO           SYSTEM PLANNING - ENOI                                DIRCTENO                1,088                 106          1,194              1,194            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PCCSPGSL           SYSTEM PLANNING - EGSI-LA                             DIRECTLG                3,058                 282          3,340              3,340            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PCCSPUTI           SYSTEM PLANNING & STRATEGIC AD                        LOADOPCO                  976                  67          1,042                869          173                  -             4             177
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PCE14423           REGULATORY AFFAIRS - EMI                              DIRCTEMI                1,046                  82          1,128              1,128            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PCSYSAGR           SYSTEM AGREEMENT-2001                                 CUSEOPCO                8,214                 702          8,916              7,593        1,323                  -            32           1,355
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PCW15830           SYSTEM GENERATION PLANNING                            LOADOPCO              906,526              79,321        985,847            830,499      155,348                  -         3,013         158,361
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PCW15840           PLANNING MODELING & ANALYSIS G                        LOADOPCO              294,177              26,854        321,031            270,703       50,328                  -           960          51,288
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PCWE0058           AWARDS & RECOGNITIONS PROGRAM                         LOADOPCO                  319                  40            359                305           54                  -             1              55
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PPAMPDEV           Advanced Mgmt Dev Program                             EMPLOYAL                    -                   -              -                  -            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PPE14432           EAI SPP RTO Study                                     DIRCTEAI                1,053                 109          1,162              1,162            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PPEAIMIS           MISO Transition EAI Path 1 cos                        DIRCTEAI                1,563                 118          1,681              1,681            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PPEMI884           EMI-2010 ECR Docket 2008-UN-88                        DIRCTEMI                  307                  32            338                338            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PPISP717           Integration Planning Studies 7                        LOADOPCO                1,653                 145          1,798              1,499          298                  -             6             305
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PPMSFA10           2010 EMI Fuel Audit                                   DIRCTEMI                  200                  21            221                221            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PPSPE003           SPO Summer 2009 RFP Expense                           LOADOPCO               10,932               1,416         12,348             10,499        1,850                  -            35           1,885
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PPSPE010           SPO Divers ty In tiative                              LOADOPCO                  581                  64            645                548           96                  -             2              98
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PPSPE024           SPO Power Delivery & Tech Serv                        LOADOPCO                  640                  57            697                581          116                  -             2             118
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PPSPE025           SPO 2010 Renewable RFP - LA on                        CUSELGLA                  513                  46            559                559            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PPSPE027           SPO ESI Project Houston PPA                           DIRCTESI                    -                   -              -                  -            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PPSPE042           SPO Expense ISES Purchase Opti                        OWNISES2                  626                  65            690                690            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PPTCGS11           TX Docket Competitive Generati                        DIRECTTX                   84                   7             91                  -           91                  -             2              93
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PPTDERSC           Entergy Regional State Committ                        LOADOPCO               12,659               1,123         13,782             11,638        2,144                  -            46           2,189
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PPTDERSD           MISO Transition ALL OPCO                              LOADOPCO               13,372               1,010         14,382             11,995        2,387                  -        (2,387)              -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PPWE0516           EPA Section 114 Request for In                        DIRCTEAI                3,836                 365          4,201              4,201            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F3PPWET308           SPO Calpine PPA/Project Housto                        DIRECTTX                3,131                 301          3,432                  -        3,432                  -            72           3,505
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F5PCEDIVER           DIVERSITY TRAINING                                    DIRCTESI                   90                   -             90                 90            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F5PCSVCAWD           SERVICE AWARDS                                        DIRCTESI                   40                   -             40                 40            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F5PP10011U           Show Cause Docket No. 10-011-U                        DIRCTEAI                  866                   -            866                866            -                  -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F5PPBULKPW           Minimize of Bulk Power Supply                         LOADOPCO               47,615               4,128         51,743             43,320        8,423                  -           171           8,594
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F5PPDOEETR           DOE-Dept of Energy Studies Coo                        LOADOPCO                  458                 186            644                544          100                  -             7             106
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F5PPETX009           2009 Texas Rate Case Support                          DIRECTTX                7,009                 645          7,654                  -        7,654               (570)       (7,084)              -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F5PPSPPCBA           ICT/RTO Cost Benefit Analysis                         LOADOPCO                  527                  54            581                494           87                  -           (87)              -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F5PPSUPICT           Support of ICT                                        LOADOPCO                4,664                 464          5,129              4,363          766                  -            16             781
9-254




                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       F5PPZUWELL           Entergy Wellness Program                              EMPLOYAL                1,357                 116          1,472              1,400           72                  -             2              74

                     ENERGY AND FUEL MANAGEMENT                ESI              SESKF       Total                                                                                          1,336,569            118,596        1,455,165         1,220,425      234,741               (570)       (5,187)        228,983

                     ENERGY AND FUEL MANAGEMENT                ESI              SESKG       F3PCW15840           PLANNING MODELING & ANALYSIS G                        LOADOPCO                    659                     -            659              550          109                -                -            109

                     ENERGY AND FUEL MANAGEMENT                ESI              SESKG       Total                                                                                                  659                     -            659              550          109                -                -            109

                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       C1PPSP0008           SPO ELL&ENOI Purchase Option I                        OWNISES2                 (964)               (100)         (1,064)           (1,064)              -               -                -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       C6PPSP0012           SPO Project Gator Transact/Tra                        DIRCTELI                2,931                 241           3,171             3,171               -               -                -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       C6PPSP0038           SPO Project Lamar Transaction                         DIRCTEAI                  266                  24             290               290               -               -                -                -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       C6PPSP0046           SPO Project Burnet Transaction                        DIRCTEMI                  353                  35             388               388               -               -                -                -

                           Amounts may not add or tie to other schedules due to rounding.
                                                                                                                                                                                                                                                                                                                                  EXHIBIT PJC-C
                                                                                                                                                                                       Cicio, Patrick                                                                                                                               Page 8 of 11
                                                                                                                                                                             ENTERGY TEXAS, INC.                                                                                                                      EXHIBIT PJC-C
2011 ETI Rate Case




                                                                                                                                                        Affiliate Billings - by Witness, Class, Department and Project                                                                                             2011 TX Rate Case
                                                                                                                                                                  For the Twelve Months Ended June 30, 2011                                                                                                              Page 9 of 11
                                                                                                                                                                               Amounts in Dollars
                                                                                                                                                                                             (A)             (B)           (C)              (D)          (E)           (F)              (G)             (H)
                                                                                                                                                                                                         Total Billings
                                                                                            Activity / Project                                                           ESI BIlling                    Service Company                                 ETI Per                      Pro Forma        Total ETI
                                      Class                    Billing Entity      Dept           Code                             Activity / Project Description         Method           Support         Recipient       Total       All Other BU's   Books       Exclusions        Amount          Adjusted
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F3PCFVARAS           ADMIN SUPRT - VARIBUS CORPORAT                        DIRECTLG                    -                 -            -                -           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F3PCSYSAGR           SYSTEM AGREEMENT-2001                                 CUSEOPCO                    -                 -            -                -           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F3PCW19501           WHOLESALE PURCHASING & SALES                          LOADOPCO                    -                 -            -                -           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F3PCW19510           ENERGY MANAGEMENT OPERATIONS                          LOADOPCO              144,037            13,246      157,282          131,852      25,430              -             491          25,921
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F3PCW19511           ENERGY MANAGEMENT OPERATIONS P                        LOADOPCO            1,506,076           129,082    1,635,158        1,376,511     258,647              -           4,838         263,485
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F3PCW54035           VICE PRESIDENT OF ENERGY MANAG                        LOADOPCO                    -                 -            -                -           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F3PCWE0058           AWARDS & RECOGNITIONS PROGRAM                         LOADOPCO                  398                50          448              382          67              -               2              69
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F3PPAMPDEV           Advanced Mgmt Dev Program                             EMPLOYAL                4,112                 -        4,112            3,921         192              -               -             192
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F3PPSPE003           SPO Summer 2009 RFP Expense                           LOADOPCO                  563                60          623              530          93              -               2              95
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F3PPSPE010           SPO Divers ty In tiative                              LOADOPCO                   30                 -           30               26           4              -               -               4
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F3PPSPE025           SPO 2010 Renewable RFP - LA on                        CUSELGLA                  486                40          527              527           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F3PPSPE027           SPO ESI Project Houston PPA                           DIRCTESI                    -                 -            -                -           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F3PPSPE042           SPO Expense ISES Purchase Opti                        OWNISES2                  964               100        1,064            1,064           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F3PPTDERSC           Entergy Regional State Committ                        LOADOPCO               10,491               949       11,439            9,541       1,899              -              40           1,939
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F3PPTDERSD           MISO Transition ALL OPCO                              LOADOPCO               20,788             1,664       22,453           18,726       3,727              -          (3,727)              -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F3PPWE0420           SPO EGSL-SupplyProcuremt/Asset                        DIRECTLG                3,199               263        3,462            3,462           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F3PPWET304           SPO Frontier 10 Year PPA                              DIRECTTX                   88                 7           95                -          95              -               2              97
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F3PPWET308           SPO Calpine PPA/Project Housto                        DIRECTTX               29,013             2,801       31,814                -      31,814              -             663          32,477
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F5PCSVCAWD           SERVICE AWARDS                                        DIRCTESI                  653                 -          653              653           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F5PCZU1424           REGULATORY AFFAIRS - NOPSI                            DIRCTENO                  923                73          995              995           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F5PCZZ4070           IMPACT AWARDS                                         DIRCTESI                  155                 -          155              155           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F5PP10011U           Show Cause Docket No. 10-011-U                        DIRCTEAI               27,194             2,447       29,641           29,641           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F5PP4RFERC           FERC Audit                                            LVLSVCAL                    -                 -            -                -           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F5PPBCNAVF           Avian Flu Contingency Planning                        EMPLOYAL                    -                 -            -                -           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F5PPETX009           2009 Texas Rate Case Support                          DIRECTTX               (1,125)                -       (1,125)               -      (1,125)          (212)          1,337               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F5PPMSFA9A           2009 EMI Fuel Audit McFadden G                        DIRCTEMI                    -                 -            -                -           -              -               -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F5PPSPE044           PMO Support Initiative-System-                        LOADOPCO               12,129               980       13,109           10,933       2,176              -          (2,176)              -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F5PPSUPICT           Support of ICT                                        LOADOPCO                 (119)                -         (119)            (101)        (18)             -              (0)            (18)
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F5PPZUWELL           Entergy Wellness Program                              EMPLOYAL                1,988               142        2,131            2,026         104              -               2             106
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       F5PPZZ580B           REGULATORY AFFAIRS-A&G                                CUSTEGOP                  769                59          828              714         114              -               2             117

                     ENERGY AND FUEL MANAGEMENT                ESI              SESKH       Total                                                                                          1,765,397           152,163    1,917,560       1,594,341      323,219             (212)        1,476         324,483

                     ENERGY AND FUEL MANAGEMENT                ESI              SESKJ       F3PCW19501           WHOLESALE PURCHASING & SALES                          LOADOPCO              626,065            39,537      665,602         560,815      104,787                -         1,982         106,769
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKJ       F3PCW19510           ENERGY MANAGEMENT OPERATIONS                          LOADOPCO            2,324,822           206,432    2,531,254       2,131,786      399,469                -         7,468         406,936
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKJ       F3PCW19511           ENERGY MANAGEMENT OPERATIONS P                        LOADOPCO                8,802               845        9,647           8,046        1,601                -            31           1,632
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKJ       F3PCW54035           VICE PRESIDENT OF ENERGY MANAG                        LOADOPCO                6,325                 -        6,325           5,297        1,028                -             -           1,028
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKJ       F5PCEDIVER           DIVERSITY TRAINING                                    DIRCTESI                  135                 -          135             135            -                -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKJ       F5PCSVCAWD           SERVICE AWARDS                                        DIRCTESI                  233                 -          233             233            -                -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKJ       F5PCZXNLDW           NEW LEADERSHIP DEVELOPMENT WOR                        EMPLOREG                   35                 -           35              33            2                -             -               2
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKJ       F5PP4RFERC           FERC Audit                                            LVLSVCAL                    -                 -            -               -            -                -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKJ       F5PPBCNAVF           Avian Flu Contingency Planning                        EMPLOYAL                    -                 -            -               -            -                -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKJ       F5PPMSFA9A           2009 EMI Fuel Audit McFadden G                        DIRCTEMI                    -                 -            -               -            -                -             -               -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKJ       F5PPZUWELL           Entergy Wellness Program                              EMPLOYAL                  149                12          161             154            8                -             0               8

                     ENERGY AND FUEL MANAGEMENT                ESI              SESKJ       Total                                                                                          2,966,567           246,827    3,213,393       2,706,497      506,896                -         9,480         516,376

                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PCCSPUTI           SYSTEM PLANNING & STRATEGIC AD                        LOADOPCO                   60                  -         60               51            9                -                -            9
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PCE14420           REGULATORY AFFAIRS - EAI                              DIRCTEAI                  184                 18        203              203            -                -                -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PCSYSAGR           SYSTEM AGREEMENT-2001                                 CUSEOPCO               99,830              7,752    107,582           91,701       15,881                -              373       16,254
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PCW15830           SYSTEM GENERATION PLANNING                            LOADOPCO                1,417                136      1,552            1,319          233                -                4          238
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PCW18200           OPNS-OIL SUPPLY                                       OWNISFI                   277                 27        304              304            -                -                -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PCWE0064           LONG TERM ENERGY                                      LOADOPCO                  935                  -        935              787          148                -                -          148
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PPE14432           EAI SPP RTO Study                                     DIRCTEAI                2,491                257      2,748            2,748            -                -                -            -
9-255




                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PPE14434           EAI POST SYS AGMT INCREMENTAL                         DIRCTEAI                8,439                569      9,008            9,008            -                -                -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PPE14435           EAI POST SYS AGMT NON-INCREMEN                        DIRCTEAI                2,616                270      2,886            2,886            -                -                -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PPEAIMIS           MISO Transition EAI Path 1 cos                        DIRCTEAI               19,544              1,268     20,813           20,813            -                -                -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PPEMIMIS           MISO Transition EMI costs                             DIRCTEMI                1,299                 84      1,382            1,382            -                -                -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PPENOIMI           MISO Transition ENOI costs                            DIRCTENO                   47                  4         50               50            -                -                -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PPETIMIS           MISO Transition ETI costs                             DIRECTTX                  358                 27        385                -          385                -             (385)           -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PPINVDOJ           DOJ Anti Trust Investigation                          CUSEOPCO                2,362                151      2,513            2,142          370                -                6          376
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PPMSFA10           2010 EMI Fuel Audit                                   DIRCTEMI                  184                 20        205              205            -                -                -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PPSPE001           SPO NISCO JOPOA MANAGEMENT EXP                        DIRECTLG                   56                  -         56               56            -                -                -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PPSPE010           SPO Divers ty In tiative                              LOADOPCO                  135                 11        146              121           24                -                1           25
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PPSPE011           SPO NISCO Contract                                    DIRECTLG                4,861                414      5,275            5,275            -                -                -            -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PPSPE017           SPO 2010 Renewable RFP                                LOADOPCO                  154                  -        154              131           23                -                -           23

                           Amounts may not add or tie to other schedules due to rounding.
                                                                                                                                                                                                                                                                                                                      EXHIBIT PJC-C
                                                                                                                                                                                       Cicio, Patrick                                                                                                                   Page 9 of 11
                                                                                                                                                                             ENTERGY TEXAS, INC.                                                                                                                     EXHIBIT PJC-C
2011 ETI Rate Case




                                                                                                                                                        Affiliate Billings - by Witness, Class, Department and Project                                                                                            2011 TX Rate Case
                                                                                                                                                                  For the Twelve Months Ended June 30, 2011                                                                                                            Page 10 of 11
                                                                                                                                                                               Amounts in Dollars
                                                                                                                                                                                             (A)             (B)           (C)              (D)          (E)           (F)              (G)           (H)
                                                                                                                                                                                                         Total Billings
                                                                                            Activity / Project                                                           ESI BIlling                    Service Company                                 ETI Per                      Pro Forma      Total ETI
                                      Class                    Billing Entity      Dept           Code                             Activity / Project Description         Method           Support         Recipient       Total       All Other BU's   Books       Exclusions        Amount        Adjusted
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PPSPE018           SPO VP of Strategic Initiative                        LOADOPCO             371,895              34,263     406,158         343,181        62,977             -            1,120        64,097
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PPSPE025           SPO 2010 Renewable RFP - LA on                        CUSELGLA                 505                  48          553             553            -             -                -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PPTDERSC           Entergy Regional State Committ                        LOADOPCO              88,884               6,164      95,049           79,752       15,297             -              319        15,615
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PPTDERSD           MISO Transition ALL OPCO                              LOADOPCO              53,896               3,669      57,565           48,010        9,555             -           (9,555)             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PPWE0403           SPO Performance Mngmnt/Special                        LOADOPCO               2,491                 234       2,725            2,273          452             -               10           462
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F3PPWET306           SPO 2011 Western Region RFP                           DIRECTTX               2,536                 208       2,743                -        2,743             -               61         2,804
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F5PCE13759           JENKINS CLASS ACTION SUIT                             DIRECTTX               1,513                 114       1,627                -        1,627             -               30         1,657
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F5PCSVCAWD           SERVICE AWARDS                                        DIRCTESI                 226                   -          226             226            -             -                -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F5PCZU1422           REGULATORY AFFAIRS - LP&L                             DIRCTELI                   43                  -           43              43            -             -                -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F5PCZU1424           REGULATORY AFFAIRS - NOPSI                            DIRCTENO                 551                  50          601             601            -             -                -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F5PCZU1574           REGULATORY AFFAIRS - 100% TX G                        DIRECTTX              16,506               1,180      17,686                -       17,686             -              265        17,951
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F5PP10011U           Show Cause Docket No. 10-011-U                        DIRCTEAI              37,874               2,841      40,715           40,715            -             -                -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F5PP4RFERC           FERC Audit                                            LVLSVCAL                    -                  -            -               -            -             -                -              -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F5PPETX009           2009 Texas Rate Case Support                          DIRECTTX               2,238                 143       2,382                -        2,382           (99)          (2,283)             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F5PPSPE044           PMO Support Initiative-System-                        LOADOPCO              44,113               3,705      47,818           39,881        7,937             -           (7,937)             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F5PPSPPCBA           ICT/RTO Cost Benefit Analysis                         LOADOPCO              33,937               3,185      37,123           31,251        5,872             -           (5,872)             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       F5PPSUPICT           Support of ICT                                        LOADOPCO              51,936               4,526      56,462           47,197        9,266             -              173         9,438

                     ENERGY AND FUEL MANAGEMENT                ESI              SESKQ       Total                                                                                            854,394             71,339    925,732          772,863      152,869              (99)      (23,673)      129,098

                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       C6PPGN0020           New Nuclear Reg Filing EGSL On                        DIRECTLG                  461                 35        496              496            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       C6PPLN0020           New Nuclear Reg Filing ELL Ong                        DIRCTELI                  461                 35        496              496            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       C6PPSP0012           SPO Project Gator Transact/Tra                        DIRCTELI                1,592                155      1,747            1,747            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       C6PPSP0038           SPO Project Lamar Transaction                         DIRCTEAI                8,708                842      9,550            9,550            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       C6PPSP0046           SPO Project Burnet Transaction                        DIRCTEMI                  322                 28        351              351            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       C6PPWS0783           Ninem le 6 Development                                DIRCTELI                7,794                768      8,562            8,562            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F3PCCSPEAI           SYSTEM PLANNING - EAI                                 DIRCTEAI               24,707              2,387     27,094           27,094            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F3PCCSPELI           SYSTEM PLANNING - ELI                                 DIRCTELI                2,799                273      3,073            3,073            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F3PCCSPEMI           SYSTEM PLANNING - EMI                                 DIRCTEMI                  922                 94      1,015            1,015            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F3PCCSPENO           SYSTEM PLANNING - ENOI                                DIRCTENO                7,197                690      7,887            7,887            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F3PCCSPGST           SYSTEM PLANNING - EGSI-TX                             DIRECTTX                2,178                180      2,358                -        2,358                -            51         2,409
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F3PCCSPUTI           SYSTEM PLANNING & STRATEGIC AD                        LOADOPCO                1,554                  -      1,554            1,322          232                -             -           232
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F3PCSYSAGR           SYSTEM AGREEMENT-2001                                 CUSEOPCO               12,170              1,027     13,197           11,247        1,950                -            40         1,990
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F3PCW15830           SYSTEM GENERATION PLANNING                            LOADOPCO              809,798             75,495    885,293          746,610      138,683                -         2,677       141,360
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F3PCW15840           PLANNING MODELING & ANALYSIS G                        LOADOPCO                  417                  -        417              354           63                -             -            63
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F3PPE14436           EAI MISO RTO STUDY                                    DIRCTEAI                1,103                 93      1,196            1,196            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F3PPEAIMIS           MISO Transition EAI Path 1 cos                        DIRCTEAI               10,103              1,071     11,174           11,174            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F3PPEAIPAT           Maintain EAI Paths 2 and 3 RTO                        DIRCTEAI                7,481                565      8,046            8,046            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F3PPISP717           Integration Planning Studies 7                        LOADOPCO               14,486              1,200     15,686           13,112        2,574                -            57         2,631
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F3PPSPE003           SPO Summer 2009 RFP Expense                           LOADOPCO               27,286              2,859     30,145           25,645        4,501                -            92         4,592
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F3PPSPE007           SPO July 2009 Flexible Baseloa                        LOADOPCO                    -                  -          -                -            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F3PPSPE017           SPO 2010 Renewable RFP                                LOADOPCO                  503                 40        542              461           81                -             2            83
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F3PPSPE025           SPO 2010 Renewable RFP - LA on                        CUSELGLA               48,223              4,424     52,647           52,647            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F3PPSPE049           SPO 2011 EAI RFP                                      DIRCTEAI                1,617                122      1,739            1,739            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F3PPTDERSD           MISO Transition ALL OPCO                              LOADOPCO                  388                 29        418              348           69                -           (69)            -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F3PPUD0802           ENO Integrated Resource Plan                          DIRCTENO                1,424                118      1,542            1,542            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F3PPWET300           SPO 2008 Western Region RFP-Te                        DIRECTTX                    -                  -          -                -            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F3PPWET302           SPO 2008 Winter Western Region                        DIRECTTX                    -                  -          -                -            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F5PCEDIVER           DIVERSITY TRAINING                                    DIRCTESI                  135                  -        135              135            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F5PCSVCAWD           SERVICE AWARDS                                        DIRCTESI                  210                  -        210              210            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F5PCZU1424           REGULATORY AFFAIRS - NOPSI                            DIRCTENO                  754                 58        812              812            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F5PCZZ4070           IMPACT AWARDS                                         DIRCTESI                   36                  -         36               36            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F5PP10011U           Show Cause Docket No. 10-011-U                        DIRCTEAI                3,705                291      3,996            3,996            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F5PPSUPICT           Support of ICT                                        LOADOPCO                  212                 22        234              199           35                -             1            36
9-256




                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       F5PPZUWELL           Entergy Wellness Program                              EMPLOYAL                  696                 51        747              711           36                -             1            37

                     ENERGY AND FUEL MANAGEMENT                ESI              SESKU       Total                                                                                            999,442             92,955   1,092,397         941,814      150,582                -         2,851       153,434

                     ENERGY AND FUEL MANAGEMENT                ESI              SESLA       F3PCFBLFOS           BELOW THE LINE - FOSSIL OPERAT                        CAPAOPCO                3,684                  -      3,684            3,286          398             (398)            -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESLA       F3PCSYSAGR           SYSTEM AGREEMENT-2001                                 CUSEOPCO                    -                  -          -                -            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESLA       F3PCW19501           WHOLESALE PURCHASING & SALES                          LOADOPCO              824,308             75,638    899,946          758,065      141,882                -         2,726       144,607
                     ENERGY AND FUEL MANAGEMENT                ESI              SESLA       F3PCWE0064           LONG TERM ENERGY                                      LOADOPCO                    -                  -          -                -            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESLA       F5PCSVCAWD           SERVICE AWARDS                                        DIRCTESI                1,861                  -      1,861            1,861            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESLA       F5PP4RFERC           FERC Audit                                            LVLSVCAL                    -                  -          -                -            -                -             -             -
                     ENERGY AND FUEL MANAGEMENT                ESI              SESLA       F5PPZUWELL           Entergy Wellness Program                              EMPLOYAL                  439                 29        468              445           23                -             0            23


                           Amounts may not add or tie to other schedules due to rounding.
                                                                                                                                                                                                                                                                                                                     EXHIBIT PJC-C
                                                                                                                                                                                       Cicio, Patrick                                                                                                                 Page 10 of 11
                                                                                                                                                                               ENTERGY TEXAS, INC.                                                                                                                           EXHIBIT PJC-C
2011 ETI Rate Case




                                                                                                                                                          Affiliate Billings - by Witness, Class, Department and Project                                                                                                  2011 TX Rate Case
                                                                                                                                                                    For the Twelve Months Ended June 30, 2011                                                                                                                  Page 11 of 11
                                                                                                                                                                                 Amounts in Dollars
                                                                                                                                                                                              (A)              (B)                (C)              (D)          (E)            (F)            (G)             (H)
                                                                                                                                                                                                           Total Billings
                                                                                               Activity / Project                                                         ESI BIlling                     Service Company                                      ETI Per                     Pro Forma        Total ETI
                                           Class                  Billing Entity    Dept             Code                            Activity / Project Description        Method           Support          Recipient            Total       All Other BU's   Books        Exclusions      Amount          Adjusted
                     ENERGY AND FUEL MANAGEMENT                   ESI            SESLA         Total                                                                                         830,292               75,667          905,959         763,656      142,303            (398)        2,726         144,631

                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLB           C6PPSP0029           SPO Evange ine                                       DIRCTELI                 161                  17             178              178            -               -             -               -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLB           C6PPWS0783           Ninem le 6 Development                               DIRCTELI               1,045                 111           1,156            1,156            -               -             -               -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLB           F3PCSYSAGR           SYSTEM AGREEMENT-2001                                CUSEOPCO                   -                   -               -                -            -               -             -               -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLB           F3PCW19502           WHOLESALE TRXN - EAI CUSTOMERS                       DIRCTEAI                  56                   -              56               56            -               -             -               -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLB           F3PCW19511           ENERGY MANAGEMENT OPERATIONS P                       LOADOPCO              21,026               1,979          23,005           19,571        3,434               -            65           3,499
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLB           F3PCWE0064           LONG TERM ENERGY                                     LOADOPCO             325,424              28,335         353,759          298,125       55,634               -         1,019          56,653
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLB           F3PPAMPDEV           Advanced Mgmt Dev Program                            EMPLOYAL               4,112                   -           4,112            3,921          192               -             -             192
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLB           F3PPAPSCLG           APSC Complaint - FERC Investig                       CUSEOPCO                   -                   -               -                -            -               -             -               -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLB           F3PPTDERSC           Entergy Regional State Committ                       LOADOPCO                   -                   -               -                -            -               -             -               -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLB           F3PPTDERSD           MISO Transition ALL OPCO                             LOADOPCO               2,144                 162           2,306            1,923          383               -          (383)              -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLB           F3PPWE0315           Dir. Southeast Region-TXT_ ELI                       CAPASTHN              18,259               1,717          19,976           19,976            -               -             -               -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLB           F5PCZU1422           REGULATORY AFFAIRS - LP&L                            DIRCTELI                   -                   -               -                -            -               -             -               -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLB           F5PP10011U           Show Cause Docket No. 10-011-U                       DIRCTEAI                   -                   -               -                -            -               -             -               -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLB           F5PP4RFERC           FERC Audit                                           LVLSVCAL                   -                   -               -                -            -               -             -               -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLB           F5PPBCNAVF           Avian Flu Contingency Planning                       EMPLOYAL                   -                   -               -                -            -               -             -               -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLB           F5PPETX009           2009 Texas Rate Case Support                         DIRECTTX                   -                   -               -                -            -              (9)            9               -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLB           F5PPMSFA9A           2009 EMI Fuel Audit McFadden G                       DIRCTEMI                   -                   -               -                -            -               -             -               -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLB           F5PPSUPICT           Support of ICT                                       LOADOPCO                   -                   -               -                -            -               -             -               -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLB           F5PPZUWELL           Entergy Wellness Program                             EMPLOYAL                 595                  43             638              607           31               -             1              32
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLB           F5PPZZ580B           REGULATORY AFFAIRS-A&G                               CUSTEGOP                 296                  23             318              274           44               -             1              45

                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLB           Total                                                                                          373,117              32,386         405,504          345,786       59,718              (9)            712        60,421

                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLC           F3PCWE0138           POWER CONTRACTS                                      LOADOPCO                   508                     -           508              427          81              -                -            81

                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLC           Total                                                                                                508                     -           508              427          81              -                -            81

                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLE           F3PCW19510           ENERGY MANAGEMENT OPERATIONS                         LOADOPCO               1,074                       -       1,074                912          162             -                -            162
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLE           F3PCWE0064           LONG TERM ENERGY                                     LOADOPCO                   1                       -           1                  1            0             -                -              0
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLE           F5PPZUWELL           Entergy Wellness Program                             EMPLOYAL                   -                       -           -                  -            -             -                -              -

                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLE           Total                                                                                            1,076                       -       1,076                914          162             -                -            162

                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLT           C6PPSP0012           SPO Project Gator Transact/Tra                       DIRCTELI                 398                  34             431              431            -               -                -            -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLT           C6PPSP0029           SPO Evange ine                                       DIRCTELI               7,474                 509           7,983            7,983            -               -                -            -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLT           F3PCFVARAS           ADMIN SUPRT - VARIBUS CORPORAT                       DIRECTLG                 373                  40             413              413            -               -                -            -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLT           F3PCW18100           OPNS-GAS SUPPLY                                      CAPXCOPC             166,313              15,649         181,962          157,095       24,867               -              471       25,338
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLT           F3PCW19501           WHOLESALE PURCHASING & SALES                         LOADOPCO             119,159              10,643         129,802          109,438       20,364               -              339       20,703
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLT           F3PCW51400           SFI FUEL OIL O&M                                     DIRCTSFI                 144                  15             159              159            -               -                -            -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLT           F3PPAMPDEV           Advanced Mgmt Dev Program                            EMPLOYAL                   -                   -               -                -            -               -                -            -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLT           F3PPMSFA10           2010 EMI Fuel Audit                                  DIRCTEMI               1,016                  85           1,102            1,102            -               -                -            -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLT           F3PPSPE003           SPO Summer 2009 RFP Expense                          LOADOPCO               2,288                 190           2,479            2,109          370               -                6          376
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLT           F3PPSPE011           SPO NISCO Contract                                   DIRECTLG                 144                  12             156              156            -               -                -            -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLT           F3PPTDERSC           Entergy Regional State Committ                       LOADOPCO                 582                  57             639              538          101               -                2          103
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLT           F3PPTDHY11           Transmission Comp iance FERC A                       TRSBLNOP                 144                  15             159              140           19               -                1           19
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLT           F5PCZU1425           REGULATORY COORDINAT.-ELI & EG                       CUSELPSC                   -                   -               -                -            -               -                -            -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLT           F5PCZU1574           REGULATORY AFFAIRS - 100% TX G                       DIRECTTX                 951                  83           1,034                -        1,034               -               20        1,054
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLT           F5PP4RFERC           FERC Audit                                           LVLSVCAL                   -                   -               -                -            -               -                -            -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLT           F5PPETX009           2009 Texas Rate Case Support                         DIRECTTX                 144                  11             155                -          155              (7)            (148)           -
                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLT           F5PPMSFA9A           2009 EMI Fuel Audit McFadden G                       DIRCTEMI                   -                   -               -                -            -               -                -            -

                     ENERGY AND FUEL MANAGEMENT                   ESI          SESLT           Total                                                                                          299,128              27,344         326,472          279,563       46,909              (7)            692        47,594
9-257




                     ENERGY AND FUEL MANAGEMENT                   Total ESI                                                                                                                23,521,673          1,732,183        25,253,856      21,510,774     3,743,083         (7,029)        6,260       3,742,314

                     Total ENERGY AND FUEL MANAGEMENT                                                                                                                                      23,521,673          1,732,183        25,253,856      21,510,774     3,743,083         (7,029)        6,260       3,742,314

                     Total Cicio Patrick                                                                                                                                                   23,521,673          1,732,183        25,253,856      21,510,774     3,743,083         (7,029)        6,260       3,742,314




                              Amounts may not add or tie to other schedules due to rounding.
                                                                                                                                                                                                                                                                                                                             EXHIBIT PJC-C
                                                                                                                                                                                        Cicio, Patrick                                                                                                                        Page 11 of 11
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2011 ETI Rate Case                       9-258
                                                                                                                          ENTERGY TEXAS, INC.                                                                EXHIBIT PJC-D
2011 ETI Rate Case




                                                                                               Affiliate Billings - Pro Forma Summary - By Witness, Class, & Pro Forma                                    2011 TX Rate Case
                                                                                                               For the Twelve Months Ended June 30, 2011                                                         Page 1 of 1
                                                                                                                            Amounts in Dollars

                                                                      Billing    Pro Forma
                                           Class                      Entity      Number                             Pro Forma Description                                        Supporting Witness   Pro Forma
                     ENERGY AND FUEL MANAGEMENT                     ESI         AJ16          Remove MISO Costs                                                      Considine, Michael P                  (41,533)
                     ENERGY AND FUEL MANAGEMENT                     ESI         AJ21-03       Remove Rate Case Support Costs                                         Considine, Michael P                  (13,552)
                     ENERGY AND FUEL MANAGEMENT                     ESI         AJ21-04       PwC - Changes in Billing Methods                                       Tumminello, Stephanie B                  (147)
                     ENERGY AND FUEL MANAGEMENT                     ESI         AJ21-05       Remove Ticket Costs                                                    Barrilleaux, Chris                       (344)
                     ENERGY AND FUEL MANAGEMENT                     ESI         AJ21-07       Remove Non-Recoverable Costs                                           Barrilleaux, Chris                     (2,705)
                     ENERGY AND FUEL MANAGEMENT                     ESI         AJ22          Affiliate Portion of Employee Changes and Wage Increases               Considine, Michael P                   64,541

                                                                    ESI                                                                                                                                     6,260

                     ENERGY AND FUEL MANAGEMENT                     Total                                                                                                                                   6,260

                     Total                                                                                                                                                                                  6,260
9-259




                             Amounts may not add or tie to other schedules due to rounding.                                                                                                                  EXHIBIT PJC-D
                                                                                                                         Cicio, Patrick                                                                         Page 1 of 1
    This page has been intentionally left blank.




2011 ETI Rate Case                       9-260
                                 SOAH Docket No. XXX-XX-XXXX
                                         PUC Docket No. 39896
                                            ETI 2011 Rate Case
                                            ETI EXHIBIT NO. 46
                  SOAH DOCKET NO. XXX-XX-XXXX
                     PUC DOCKET NO. 39896

APPLICATION OF ENTERGY         §
TEXAS, INC. FOR AUTHORITY TO   §             BEFORE THE
CHANGE RATES, RECONCILE        §           STATE OFFICE OF
FUEL COSTS, AND OBTAIN         §       ADMINISTRATIVE HEARINGS
DEFERRED ACCOUNTING            §
TREATMENT                      §




                     REBUTTAL TESTIMONY


                               OF


                     MICHAEL P. CONSIDINE


                         ON BEHALF OF


                     ENTERGY TEXAS, INC.




                          APRIL 2012




                                                                 1
                         ENTERGY TEXAS, INC.
             REBUTTAL TESTIMONY OF MICHAEL P. CONSIDINE
                        PUC DOCKET NO. 39896


                            TABLE OF CONTENTS
                                                          Page

I.     Introduction                                          1 

       A.    Introduction and Qualifications                 1 

II.    Rebuttal Issues                                       2 

       A.    Spindletop Gas Storage Facility                 2 

       B.    MISO Transition Expenses                        5 

       C.    Hurricane Rita Regulatory Asset                16 

       D.    Pension Asset in Rate Base                     22 

       E.    Property Insurance Reserve                     25 

       F.    Payroll and Incentive Compensation             29 

       G.    DSM Costs                                      35 

       H.    MSS-2 Costs                                    36 

       I.    Nuclear Decommissioning                        38 

       J.    Depreciation                                   40 

       K.    Fully Accrued Depreciation                     43 

       L.    Net Salvage                                    48 

       M.    Accounting For Removal Costs                   51 




                                                             2
                                 EXHIBITS

Exhibit MPC-R-1   MISO Transition Expenses for the Nine Months Ended
                  March 2012

Exhibit MPC-R-2   Rita Regulatory Asset Calculation

Exhibit MPC-R-3   Company Response to Cities 6-2 RFI

Exhibit MPC-R-4   1995 Storm Damage Policy

Exhibit MPC-R-5   ETI Payroll Adjustment

Exhibit MPC-R-6   ESI Payroll Adjustment

Exhibit MPC-R-7   Full Time Equivalent Calculation

Exhibit MPC-R-8   ETI Direct Costs of Incentive Comp Adjustment

Exhibit MPC-R-9   ESI Allocated Costs of Incentive Comp Adjustment

Exhibit MPC-R-10 March 2012 MSS-2 Bill to ETI

Exhibit MPC-R-11 Railroad Commission of Texas PFDs and Orders




                                                                       3
     Entergy Texas, Inc.                                                 Page 1 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1                                    I.      INTRODUCTION

2                             A.      Introduction and Qualifications

3    Q.     PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.

4    A.     My name is Michael P. Considine. My business address is 425 West

5           Capitol Avenue, Little Rock, Arkansas 72201.

6

7    Q.     DID YOU PREVIOUSLY FILE DIRECT TESTIMONY ON BEHALF OF

8           ENTERGY TEXAS, INC. (“ETI” OR “THE COMPANY”) IN THIS

9           PROCEEDING?

10   A.     Yes.

11

12   Q.     WHAT IS THE PURPOSE OF THIS TESTIMONY?

13   A.     The purpose of my Rebuttal Testimony is to respond to various issues

14          raised in Staff and Intervenor Direct Testimonies.

15

16   Q.     DO YOU SPONSOR ANY EXHIBITS?

17   A.     Yes.     I sponsor the exhibits listed in the Table of Contents to this

18          testimony.




                                                                                   4
     Entergy Texas, Inc.                                                                 Page 2 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1                                    II.        REBUTTAL ISSUES

2                            A.        Spindletop Gas Storage Facility

3    Q.     WHAT ISSUES DO YOU ADDRESS IN THIS SECTION OF YOUR

4           REBUTTAL TESTIMONY?

5    A.     I will address certain aspects of Cities’ witness Karl J. Nalepa’s

6           recommendation         regarding          the   Spindletop   Gas       Storage   Facility

7           (“Spindletop”)     and         I   will   address   Staff    witness     Anna    Givens

8           recommendation to remove an Electric Plant Acquisition asset related to

9           Spindletop from rate base.

10                  Mr. Nalepa recommends removing Spindletop costs from base

11          rates and also recommends removing variable non-gas operating costs

12          from eligible fuel expense because he believes the supply reliability and

13          swing flexibility provided by Spindletop can be obtained elsewhere at a

14          lower cost. Company witness Karen M. McIlvoy will address Mr. Nalepa’s

15          concerns regarding supply reliability and swing flexibility. I will address his

16          recommendation to remove the costs from base rates and eligible fuel

17          expense.

18

19   Q.     PLEASE DISCUSS MR. NALEPA’S RECOMMENDATION TO REMOVE

20          SPINDLETOP FROM RATES.

21   A.     Mr. Nalepa recommends that Spindletop be removed from rates and he

22          recommends selling the facility or removing it from regulated service if




                                                                                                   5
     Entergy Texas, Inc.                                                        Page 3 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1             necessary.1 He has prepared a Total Cost Impact table,2 which shows

2             what he claims to be the total annual costs of operating the facility. He

3             further claims that ETI’s customers pay 100% of the costs of operating

4             Spindletop.3

5

6    Q.       DO YOU AGREE WITH MR. NALEPA’S ANALYSIS AND HIS CLAIM

7             THAT ETI’S CUSTOMERS PAY 100% OF THE COSTS OF OPERATING

8             SPINDLETOP?

9    A.       No. Mr. Nalepa’s calculation fails to recognize that 57.50% of the costs

10            associated with Spindletop are billed to Entergy Gulf States Louisiana, Inc.

11            (“EGSL”) as part of the MSS-4 billing process between ETI and EGSL for

12            its “legacy” plants (that is, the generation-related facilities now owned

13            separately by either ETI or EGSL that, prior to the jurisdictional separation,

14            were owned by Entergy Gulf States, Inc.). Mr. Nalepa’s recommendation

15            as it is currently proposed is to remove all of the Spindletop costs from

16            rates and to leave the MSS-4 revenues in rates, thereby creating a

17            windfall for customers. Mr. Nalepa’s recommendation also fails to address

18            what ETI should do if it were to sell or de-regulate the facility as he

19            suggests or what to do with the gas inventory that is currently in

20            Spindletop.




     1
          Nalepa Direct at 5, line 18 and at 27, line 2.
     2
          Id. at 19, Table 9.
     3
          Id. at 19, line 3.



                                                                                          6
     Entergy Texas, Inc.                                                        Page 4 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1    Q.     WHAT IS YOUR RECOMMENDATION REGARDING MR. NALEPA’S

2           SPINDLETOP ADJUSTMENT?

3    A.     The Commission should reject Mr. Nalepa’s Spindletop adjustment. He

4           has failed to consider all of the impacts associated with his adjustment

5           and, as discussed by Company witness McIlvoy, the Spindletop facility

6           continues to provide customers with supply reliability and swing flexibility.

7           It should also be noted that ever since and including Docket No. 10894,

8           the Commission has consistently allowed the Company to recover its

9           costs associated with the Spindletop Facility because it is a used and

10          useful gas storage facility that provides benefits to ratepayers.

11

12   Q.     ON PAGE 35 OF 36, LINES 8-13, MS. GIVENS REMOVES AN

13          ELECTRIC PLANT ACQUISITION ASSET FROM THE RATE BASE OF

14          ETI.    WHAT ARE THE FACTS REGARDING THE ORIGINATION OF

15          THAT ELECTRIC PLANT ACQUISITION ASSET?

16   A.     The acquisition asset represents the incurred closing costs of $211,209

17          and legal and internal costs of $916,568 the Company incurred in

18          acquiring the Spindletop gas storage facility.     Prior to December 2009

19          those amounts were included in the Electric Plant in Service (FERC

20          Account 101).         Furthermore, these amounts were included in the

21          Company’s filed rate base amounts in PUCT Docket Nos. 34800 and

22          37744. On January 11, 2010, the FERC issued Opinion No. 505 in FERC

23          Docket No. ER07-956-001. The FERC ordered the Company to transfer



                                                                                          7
     Entergy Texas, Inc.                                                   Page 5 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1           the amounts above from Account 101 to FERC Account 114, Electric Plant

2           Acquisition Adjustments.

3

4    Q.     SHOULD THIS AMOUNT BE REMOVED FROM THE COMPANY’S RATE

5           BASE?

6    A.     No. The Company incurred this cost in conjunction with the purchase of a

7           viable asset that benefits its retail customers. The amount has previously

8           been included in the Company rate base.           The only thing that has

9           changed is that the amount is in a different account.        It would be

10          inappropriate to penalize the Company because of an accounting

11          technicality.

12

13                              B.      MISO Transition Expenses

14   Q.     WHAT ISSUES DO YOU ADDRESS IN THIS SECTION OF YOUR

15          REBUTTAL TESTIMONY?

16   A.     I will address various concerns regarding ETI’s MISO transition expenses

17          expressed by Cities’ witnesses James Z. Brazell and Mark E. Garrett and

18          TIEC witness Jeffry Pollock and Staff witness Joe Luna.         Company

19          witnesses Jay A. Lewis and Bret R. Perlman also address certain aspects

20          of their recommendations.




                                                                                     8
     Entergy Texas, Inc.                                                        Page 6 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1    Q.       WHAT IS MR. BRAZELL’S CONCERN REGARDING ETI’S MISO

2             TRANSITION EXPENSES?

3    A.       Mr. Brazell has expressed a concern that the Company has not been clear

4             with the Commission and the other parties in this case regarding its

5             request related to MISO transition expenses. 4

6

7    Q.       WHAT IS THE COMPANY’S PRIMARY REQUEST REGARDING MISO

8             TRANSITION EXPENSES?

9    A.       The Company’s primary request regarding MISO transition expenses is

10            that the Commission issue an accounting order permitting it to defer all

11            MISO-related transition O&M expenses incurred on or after January 1,

12            2011 as a Regulatory Asset. This is clearly explained in the filing the

13            Company made in Docket No. 39741 (which has been consolidated with

14            the instant docket) and in the supplemental direct testimony of Company

15            witness Lewis in this Docket.

16

17   Q.       WHAT IS THE COMPANY’S ALTERNATIVE REQUEST REGARDING

18            MISO TRANSITION EXPENSES?

19   A.       The Company’s alternative request is that it be allowed to include

20            $4 million of O&M expenses in base rates for costs associated with these

21            MISO transition expenses.           This is explained in my direct testimony

22            starting on page 21, line 29 through page 22, line 7, in Mr. Lewis’

     4
          Brazell Direct at 23, line 12.



                                                                                          9
     Entergy Texas, Inc.                                                     Page 7 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1             supplemental direct testimony starting on page 4, line 16 through page 5,

2             line 7 and in Company Adjustment 16L, WP/P AJ 16.20 through WP/P AJ

3             16.23.

4

5    Q.       WHY DOES MR. BRAZELL BELIEVE THAT THE COMPANY HAS NOT

6             BEEN CLEAR REGARDING ITS PROPOSED AND ALTERNATIVE

7             TREAMENT OF MISO TRANSITION EXPENSES?

8    A.       Mr. Brazell states that he was unaware that the Company’s $111.8 million

9             rate increase request included the $4 million amortization of MISO

10            transition expenses until my deposition.5 He states that he has reviewed

11            various documents, including the documents I reference above, which

12            discuss MISO transition expenses but was not made fully aware of the

13            Company’s proposed and alternative recommendations regarding MISO

14            transition expenses.	6

15                     Contrary to Mr. Brazell’s testimony, my direct testimony and

16            workpapers make clear that the $4 million for MISO transition expenses is

17            included in the Company’s proposed rate increase, but will be withdrawn

18            in the event that deferred accounting is allowed. My direct testimony sets

19            out that all the “adjustments” therein represent items that are either

20            included in or excluded from the Company’s cost of service.7 Adjustment

21            16, to include an amortized recovery of MISO transition expense, is

     5
          Id. at 22, line 13.
     6
          Id. at 20, lines 15-20 and at 22 lines 1-14.
     7
          Considine Direct at 13, lines 11-16.



                                                                                      10
     Entergy Texas, Inc.                                                        Page 8 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1             therefore defined in my testimony as part of the Company’s request. This

2             is further supported by the explanatory discussion of the adjustment,

3             which states that the adjustment will be “withdrawn” if deferred accounting

4             is authorized.8

5

6    Q.       PLEASE DISCUSS MR. BRAZELL’S CONCERN THAT THE COMPANY

7             “HAS BEEN LESS THAN FORTHCOMING”9 WHEN ADDRESSING ITS

8             REQUEST RELATED TO MISO TRANSITION EXPENSES.

9    A.       Mr. Brazell refers to what he characterizes as a footnote in the workpaper

10            to Schedule P, Adjustment 16L of the Rate Filing Package, and includes a

11            quote in his testimony as if it is directly from this “footnote.” 10 His quote

12            states “ETI is not seeking base rate recovery of these costs in this filing

13            because all the costs have not yet been incurred.”11 From this quote, Mr.

14            Brazell concludes that ETI expressly represented that it was not including

15            the MISO transition expenses in its request.

16                     The quote Mr. Brazell is referring to is included in the Company’s

17            explanatory description of the adjustment included on page WP/P AJ

18            16.23 in the filing package, and takes the form of full text discussion, not a

19            footnote. The actual quote from the workpaper reads: “The Company is

20            not seeking rate base treatment of these costs in this filing because all the

21            costs have not yet been incurred.” Mr. Brazell inverted the words “rate”
     8
          RF Page WP/P AJ 16.23.
     9
          Brazell Direct at 23, line 13.
     10
          Id. at 23, line 14.
     11
          Id. at 23, line 15.



                                                                                         11
     Entergy Texas, Inc.                                                      Page 9 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1            and “base,” which completely and erroneously alters the intent and

2            meaning of the Company’s explanation.

3                   The difference between the use of the words base rate and rate

4            base is significant. The proposed treatment in this filing (which will be

5            withdrawn upon grant of deferred accounting) allows the Company to

6            recover most of these costs as they are being incurred.12    The Company

7            made clear that it is not seeking “rate base” treatment (i.e., include the

8            unamortized balance of MISO transition expenses in rate base and earn a

9            return) because under this alternative treatment the Company would be

10           recovering most of the expenses as they are incurred, such that it would

11           be reasonable to forgo the recovery of carrying costs on the unamortized

12           balance. This explanation is fully consistent with the inclusion of the MISO

13           expense in the Company’s proposed base rate increase.

14

15   Q.      HAVE YOUR READ MR. BRAZELL’S DEPOSITION THAT WAS TAKEN

16           APRIL 4, 2012 IN THIS DOCKET?

17   A.      Yes.




     12
          WP/P AJ 16.23, SCHED_COS_WP_7-139.



                                                                                       12
     Entergy Texas, Inc.                                                           Page 10 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1    Q.       DID HE MAKE ANY ACKNOWLEDGEMENTS OR CONCESSIONS

2             DURING HIS DEPOSITION REGARDING THE COMPANY’S MISO

3             ADJUSTMENT?

4    A.       Yes. Mr. Brazell acknowledged a number of issues in his deposition that

5             are pertinent to his discussion of the Company’s MISO transition

6             adjustment. First, he acknowledged that he had not reviewed my direct

7             testimony.13      Second, he acknowledges that adjustments included in

8             Schedule A-3 either include or exclude expenses from the cost of

9             service.14 Third, he acknowledges that he made an error in using the term

10            “base rate” instead of “rate base” in his discussion of the Company’s

11            Adjustment 16L.15 Lastly, he acknowledges that if the Company had not

12            included the $4 million alternative amortization in its initial rate filing that it

13            could not have included it in the cost-of service after the initial rate filing

14            had been made.16




     13
          Brazell deposition at 91, lines 11-16.
     14
          Brazell deposition at 91, line 17 through page 92 line 24.
     15
          Brazell deposition at 95, line 25.
     16
          Brazell deposition at 100, lines 17-21.



                                                                                              13
     Entergy Texas, Inc.                                                      Page 11 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1    Q.       DID ANY OF THE OTHER INTERVENOR OR STAFF WITNESSES

2             EXPRESS MR. BRAZELL’S CONCERN THAT THE COMPANY’S

3             REQUEST REGARDING MISO TRANSITION EXPENSES WAS NOT

4             CLEAR?

5    A.       No.    Mr. Garrett, to whom Mr. Brazell refers,17 does not express this

6             concern and in fact his testimony accurately describes the Company’s

7             proposed and alternative request regarding MISO transition expenses.18

8             Mr. Pollock and Mr. Joe Luna also accurately describe the Company’s

9             request in their direct testimony.19

10

11   Q.       CAN YOU ADDRESS MR. GARRETT’S AND MR. POLLOCK’S

12            RECOMMENDATION REGARDING THE COMPANY’S ALTERNATIVE

13            MISO       TRANSITION            EXPENSE        ADJUSTMENT   SHOULD    THE

14            COMMISSION DENY THE COMPANY’S REQUEST FOR DEFERRED

15            ACCOUNTING?

16   A.       Both Mr. Garrett and Mr. Pollock recommend that ETI be allowed to

17            include only the test year level of expenses related to MISO transition

18            expenses. The primary reason for their recommendation of the test year

19            level of expenses is because they do not believe that the MISO transition

20            costs are known and measurable.




     17
          Brazell Direct at 24, line 9.
     18
          Garrett Direct at 61, line 15 through 62, line 9.
     19
          Pollock Direct at 45, line 7 through 46, line 9.



                                                                                        14
     Entergy Texas, Inc.                                                      Page 12 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1                     These costs are known and measurable. The $4 million that the

2             Company has included in this filing is a conservative estimate of the

3             amount of costs that the Company will incur during its transition to MISO.

4             During the nine months since the end of the test year through March 2012,

5             the Company has incurred approximately $3.6 million in MISO transition

6             expenses as shown on Exhibit MPC-R-1. On an annualized basis, this

7             would be $4.8 million. Mr. Lewis will further address the issue of future

8             MISO transition expenses in his rebuttal testimony.

9

10   Q.       PLEASE ADDRESS MR. LUNA’S RECOMMENDATIONS IN THIS

11            DOCKET.

12   A.       Mr. Luna indicated that his direct testimony would address issues 6, 7 and

13            8 that were identified in the Commission’s Preliminary Order, dated

14            December 19, 2011 in this docket.20 He is not providing testimony on the

15            Company’s request to defer MISO transition expenses.          I will address

16            issues 6 through 8 and Mr. Luna’s recommendation regarding each of

17            these issues below.

18            Issue 6 - What amount of expenses, if any, related to analyzing and
19            planning for a transition to a regional transmission organization is included
20            in Entergy’s requested cost of service? If an amount is included, how is
21            Entergy proposing to recover these costs? If so, should such expenses
22            be recovered in Entergy’s base rates?
23
24                    The Company’s primary request is that it be allowed to defer costs

25            related to analyzing and planning for a transition to a regional transmission

     20
          Luna Direct at 4, lines 15 through Page 5, line 4.



                                                                                        15
     Entergy Texas, Inc.                                                             Page 13 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1            organization (“MISO transition expenses”) it has incurred on or after

2            January 1, 2011. The mechanics of any transition expense recovery is

3            proposed to be determined in a future rate proceeding.                     Company

4            witnesses Lewis and Perlman further discuss this deferral issue in their

5            testimonies.

6                    In the alternative, should the Commission deny the Company’s

7            deferred accounting request, the Company has included MISO transition

8            expenses in its requested cost-of-service (“COS”).                 The Company’s

9            alternative recommendation regarding MISO transition expenses incurred

10           on or after January 1, 2011, has included $4 million in COS expenses

11           related to MISO transition expenses that are estimated to be incurred over

12           a three-year period beginning January 1, 2011.21

13                   The Company has also included in COS expense, amortization of

14           $52,782 in MISO transition expenses and $137,232 in rate base for

15           capitalized MISO transition expenses incurred during the time period July

16           1, 2010 through December 31, 2010 (the first six months of the test

17           year).22 In the Company’s instant application it is seeking to defer these

18           MISO related transition expenses incurred during the first six months of

19           the test year and to recover them over a five-year period.23

20                   The Company is proposing to include the MISO transition expenses

21           incurred on or after January 1, 2011 in base rates should the Commission

     21
          RF Page WP/P AJ 16.23.
     22
          $211,126 in MISO transition expenses less $73,894 in deferred Federal Income Taxes.
     23
          RF Page WP/P AJ 16.21 – WP/P AJ 16.22.



                                                                                                16
     Entergy Texas, Inc.                                                   Page 14 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1            deny the Company’s proposed deferred accounting.         The Company’s

2            MISO transition expenses incurred during the first six months of the test

3            year are requested to be included in base rates as part of the instant

4            proceeding.

5                   This is the only issue that Mr. Luna addresses in his direct

6            testimony. He recommends removing all of the amounts discussed above

7            from the COS. He has not proposed a recovery mechanism for these

8            expenses and his recommendation in effect disallows the Company any

9            opportunity to recover these expenses should the Commission deny the

10           Company’s deferral request. He does not discuss the reasonableness or

11           necessity of these expenses and he does not express an explicit opinion

12           as to whether or not MISO transition expenses should be recovered

13           through base rates or through some other mechanism.

14                  At a minimum, Mr. Luna should have included the Company’s test

15           year level of expenses in base rates should the Commission deny the

16           Company’s request for deferred accounting.

17           Issue 7 – What amount, if any, related to analyzing and planning for a
18           transition to a regional transmission organization were in Entergy’s books
19           during the test year? Were any such amounts removed from the test year,
20           and if so what were those amounts? Are any such amounts included in
21           the costs for which Entergy seeks deferral in Docket No. 39741?

22                  During the test year, the Company recorded $916,535 on its books

23           for MISO related transition expenses.24



     24
          See WP/P AJ 16.21.



                                                                                     17
     Entergy Texas, Inc.                                                  Page 15 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1                   The $916,535 was removed from the test year expenses.         See

2            discussion above regarding Issue 6 for a further description of how the

3            Company is requesting to treat pre- and post- January 1, 2011, transition

4            expenses.

5                   $652,627 of the $916,535 identified above is included in the costs

6            for which Entergy seeks deferral in Docket No. 39741.25

 7           Issue 8 – Has Entergy made any adjustments for costs related to
 8           analyzing and planning for a transition to a regional transmission
 9           organization incurred outside of the test year, and if so, what is the
10           amount and how is Entergy proposing to recover such costs?

11                  As discussed above in Issue 6, the Company’s primary request is

12           to defer costs related to MISO transition expenses incurred on or after

13           January 1, 2011. Should the Commission deny the Company’s deferred

14           accounting request, the Company’s alternative recommendation includes

15           these costs in base rates through an amortization of transition expenses

16           which will be incurred during the transition period. The Company has

17           included $3,347,373 in the COS for expenses incurred outside of the test

18           year through its $4 million amortization adjustment.26 As noted above,

19           Exhibit MPC-R-1 shows that the Company has incurred approximately

20           $3.6 million in MISO transition expenses in the nine months since the end

21           of the test year.




     25
          See WP/P AJ 16.21 ($32,173+$620,454=$652,627).
     26
          ($4,000,000-$652,627=$3,347,373).



                                                                                    18
     Entergy Texas, Inc.                                                    Page 16 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1    Q.     PLEASE SUMMARIZE YOUR RESPONSE TO THE CONCERNS ABOUT

2           MISO TRANSITION EXPENSES EXPRESSED BY THE VARIOUS

3           PARTIES.

4    A.     The Company’s proposed deferred accounting treatment and its proposed

5           alternative recommendation regarding MISO transition expenses are

6           clearly set out in this filing.       This concern expressed by Mr. Brazell

7           regarding the MISO transition expenses should not be given any weight by

8           the Commission when reviewing the Company’s deferred accounting

9           request. Should the Commission deny the Company’s proposed deferred

10          accounting request, then it is appropriate to include the Company’s

11          proposed alternative recommendation to include $4 million in MISO

12          transition expenses in its rate request as a known and measurable

13          adjustment to test year expense.

14

15                           C.      Hurricane Rita Regulatory Asset

16   Q.     WHAT ISSUES DO YOU ADDRESS IN THIS SECTION OF YOUR

17          REBUTTAL TESTIMONY?

18   A.     I will address concerns regarding ETI’s Hurricane Rita Regulatory Asset

19          expressed by Mr. Garrett and Ms. Givens.




                                                                                      19
     Entergy Texas, Inc.                                                    Page 17 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1    Q.     HAVE YOU REVIEWED MR. GARRETT’S TESTIMONY REGARDING

2           THE HURRICANE RITA REGULATORY ASSET AS DESCRIBED ON

3           PAGES 11 AND 12 OF HIS DIRECT TESTIMONY?

4    A.     Yes. Mr. Garrett claims that ETI was required to amortize the regulatory

5           balance presented in the Company’s last rate case, Docket No. 37744.

6           As a result, he contends that the asset should be reduced from its current

7           level of $26,229,627 to $10,714,557 effectively requiring the Company to

8           write off the difference of $15,515,070.

9

10   Q.     DO YOU AGREE WITH MR. GARRETT’S POSITION REGARDING THE

11          REGULATORY ASSET?

12   A.     No. There was no instruction in the Stipulation and Settlement Agreement

13          or the Final Order filed in Docket No. 37744 that states that ETI was to

14          begin amortizing this Rita Regulatory Asset, or otherwise directing the

15          treatment of the asset. Furthermore, the settlement agreement in Docket

16          No. 32097 (the case in which the level of recoverable Hurricane Rita costs

17          was identified) provided that the level of insurance credited against these

18          costs would be “trued up to reflect the difference between the $65.7 million

19          credited and all insurance payments actually received by the Company

20          related to Hurricane Rita for Texas Retail.”      Moreover, this settlement

21          provided that carrying costs would apply to the true-up amount “until such

22          trued-up amount (plus associated carrying costs at the rate of 7.9% per

23          annum) is recovered in base rates.”        ETI’s request to include the full



                                                                                      20
     Entergy Texas, Inc.                                                      Page 18 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1           Hurricane Rita regulatory asset in base rates here is consistent with the

2           provisions of the settlement that specifically apply to it.

3

4    Q.     REGARDLESS OF THE FACT THAT YOU DISAGREE WITH MR.

5           GARRETT’S          OPINION        ON   THE    AMORTIZATION        OF      THE

6           REGULATORY ASSET, HAVE YOU REVIEWED THE PROPOSED

7           CALCULATION MR. GARRETT SUPPORTS IN EXHIBIT MG2.3?

8    A.     Yes.

9

10   Q.     DO YOU HAVE ANY CORRECTIONS OR CONCERNS WITH MR.

11          GARRETT’S CALCULATION IN EXHIBIT MG2.3?

12   A.     In the event that his position were to prevail, which it should not, I have

13          two corrections to Mr. Garrett’s calculation.          First, Mr. Garrett has

14          incorrectly assumed that the $26,229,627 Regulatory Asset does not

15          include the $5,678,960 the Company received in additional Hurricane Rita

16          insurance proceeds since the Docket No. 37744 filing. The $5,678,960

17          the Company received in additional Hurricane Rita insurance proceeds

18          since Docket No. 37744 is included in the $46,013,904 shown on WP/P

19          AJ 15.3 and the Company’s rate filing package (referring to WP/P AJ 15.3)

20          clearly shows that the $46,013,904 of insurance proceeds received is a

21          component of the $26,229,627.          Mr. Garrett’s adjustment for this $5.6

22          million would remove the amount a second time from the regulatory asset




                                                                                        21
     Entergy Texas, Inc.                                                     Page 19 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1           balance. Accordingly, this amount should not be removed a second time

2           as Mr. Garrett does on Line 9 of Exhibit MG-2.3.

3                   Secondly, even if Mr. Garrett’s assumption that the Company was

4           required to amortize this balance were true, the Company would not have

5           incurred 22.5 months of amortization at the time of the filing. Mr. Garrett

6           calculates the amortization period to be from the time rates went into

7           effect as a result of Docket No. 37744 (August 15, 2010) through the time

8           revised rates are to go into effect in this docket (June 30, 2012).

9           Effectively, Mr. Garrett is making post-test year adjustments for rate base

10          items. Again, assuming Mr. Garrett’s assumption that the Company was

11          allowed to amortize this Regulatory Asset were true, it would be

12          appropriate to amortize the Asset for 10.5 months only (August 15, 2010

13          through June 30, 2011).           These two corrections adjust Mr. Garrett’s

14          Exhibit MG2.3 remaining regulatory asset balance from $10,714,557 to

15          $21,805,940. Please see my Exhibit MPC-R-2.

16

17   Q.     DOES       ANY      OTHER        WITNESS     DISCUSS     MR.    GARRETT’S

18          CALCULATION OF THE HURRICANE RITA REGULATORY ASSET?

19   A.     Yes. Cities’ witness Mr. Jacob Pous is recommending that the balance be

20          added to and amortized in the storm reserve over twenty years.




                                                                                       22
     Entergy Texas, Inc.                                                    Page 20 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1    Q.     DO YOU AGREE WITH THIS RECOMMENDATION?

2    A.     No.    Securitization, which is the explicit reason for the creation of the

3           Regulatory Asset, is intended to provide the Company with cost recovery

4           in an expedited manner. Mr. Pous’ recommendation would extend the

5           recovery over a twenty year period, which is clearly contrary to the

6           objective of securitization.

7

8    Q.     PLEASE DISCUSS MS. GIVENS’ TESTIMONY WITH REGARD TO THE

9           HURRICANE RITA REGULATORY ASSET?

10   A.     Ms. Givens testifies that it is reasonable to assume that the Hurricane Rita

11          regulatory asset was considered as part of the settlement in Docket No.

12          37744 and because PURA 36.402(c) requires the Company to request

13          recovery in its next base rate proceeding, Docket No. 37744, the

14          Company isn’t allowed to do so in this proceeding. She recommends that

15          the entire regulatory asset be removed from rate base.

16

17   Q.     DO YOU AGREE WITH MS. GIVENS’ OPINION?

18   A.     No. As I explained above, there was no instruction in the Stipulation and

19          Settlement Agreement or the Final Order filed in Docket No. 37744 that

20          states that ETI was to begin amortizing this Hurricane Rita Regulatory

21          Asset, or otherwise directing the treatment of the asset. Moreover, as

22          previously explained, the Docket No. 32907 settlement does specifically

23          address the treatment of this asset and supports the Company’s position.



                                                                                      23
     Entergy Texas, Inc.                                                             Page 21 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1            Finally, PURA § 36.402(c) does not apply to Hurricane Rita costs. The

2            securitization provisions for Hurricane Rita are found in Chapter 39,

3            Subchapter J of PURA, not Chapter 36.27

4                    Moreover, even erroneously assuming that Docket No. 37744

5            somehow resolved the recovery of the Hurricane Rita regulatory asset as

6            it was presented at that time, it still makes no sense to disallow the entire

7            asset. ETI did not seek recovery of the entire asset all at once at that

8            time, but instead recovery over a period of years through amortization. At

9            most, Ms. Givens’ erroneous reading of the settlement could relate to the

10           portion of the amortization that would result from Docket No. 37744, not

11           the entire amount of the asset.

12

13   Q.      SHOULD        THE     FACT      THAT     ETI    DID     NOT     AMORTIZE        THE

14           REGULATORY ASSET FOLLOWING DOCKET NO. 37744 PRECLUDE

15           ETI FROM BEING ALLOWED TO RECOVER THESE COSTS?

16   A.      No.




     27
          See, for example, PURA § 39.459(a)(1) (defining “hurricane reconstruction costs” as those
          related to Hurricane Rita).



                                                                                                24
     Entergy Texas, Inc.                                                   Page 22 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1                                 D.   Pension Asset in Rate Base

2    Q.       MR. GARRETT STATES THAT ETI’S PENSION CONTRIBUTIONS IN

3             EXCESS OF SFAS 87 COSTS ARE DISCRETIONARY PAYMENTS.28 IS

4             THAT A TRUE STATEMENT?

5    A.       No. ETI has made contributions to the pension fund in accordance with

6             contribution guidelines established by the Employee Retirement Income

7             Security Act of 1974, as amended, and the Internal Revenue Code of

8             1986, as amended. These contributions were fully within the range of

9             contributions deductible for tax purposes.

10

11   Q.       IS THERE ANY OTHER GUIDANCE ETI USES TO DETERMINE THE

12            PENSION CONTRIBUTIONS?

13   A.       Yes. The required pension contributions are also affected by guidance

14            pursuant to the Pension Protection Act of 2006 rules, effective beginning

15            with the 2008 plan year.

16

17   Q.       MR. GARRETT IMPLIES THAT RATEPAYER BENEFITS ARE LIMITED

18            TO THE LEVEL PROVIDED BY THE ACTUAL PENSION FUND

19            EARNINGS. DO YOU AGREE?

20   A.       No.    Ratepayers benefit from contributions made to the pension fund.

21            ASC 715-30 (formerly FAS 87) pension cost included in COS includes the

22            expected rate of return on assets. The expected long-term rate of return

     28
          Garrett at 8, Line 5.




                                                                                     25
     Entergy Texas, Inc.                                                    Page 23 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1           is 8.5%, not the actual earnings as implied by Mr. Garrett. While there are

2           market fluctuations that affect the value of the pension assets, Mr.

3           Garrett’s reference to the performance of the pension assets over the last

4           five years simply points out that the customer is receiving a benefit from

5           pension contributions 6 times greater (8.5% compared to 1.37% according

6           to Mr. Garrett) than the actual return on the funds during that period, and

7           Mr. Garrett's proposed adjustment to increase expenses to reflect the

8           benefit to customers from the return on these funds should similarly be

9           increased by a factor of more than 6.

10

11   Q.     DOES      THE     COMPANY’S           RATE   BASE   TREATMENT    OF     THE

12          CONTRIBUTIONS TO THE PENSION FUND IN EXCESS OF FAS 87

13          COST REPRESENT COMPANY-SUPPLIED FUNDS OR CUSTOMER-

14          SUPPLIED FUNDS?

15   A.     The debit balance in the pension liability account represents the excess of

16          Company supplied funds above the amount of ASC 715-30 (formerly FAS

17          87) cost assumed to be recovered from customers and should earn the

18          Company’s requested return on rate base. This balance is no different

19          than other prepayments, which are included in rate base and earn a full

20          return on rate base. Furthermore, the Company would be allowed to earn

21          a full return on rate base had the Company invested these same dollars in

22          Plant in Service, but the Company in this case used funds to contribute to

23          a still under-funded pension plan and at the same time provided a timely



                                                                                      26
     Entergy Texas, Inc.                                                          Page 24 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1            reduction to ASC 715-30 (formerly FAS 87) annual pension cost

2            immediately benefitting ratepayers.

3

4    Q.      DO YOU HAVE ANY OTHER COMMENTS REGARDING THIS ISSUE?

5    A.      Yes. Should the Commission reject the Company’s position and instead

6            apply in this case the previous Commission ruling that distinguishes the

7            portion of the pension asset related to Construction Work in Progress

8            (“CWIP”) from the remainder of the asset, it should fully apply the effect of

9            that precedent. In Docket No. 33309, Finding of Fact 32, the Commission

10           concluded that “the pension prepayment asset of $112.4 million, less the

11           $22.79 million portion included in CWIP, should be included in rate

12           base.”29 However, following court litigation regarding the issue, the courts

13           reversed the Commission’s ruling and the Commission altered its

14           treatment on remand. In the remand proceeding, Docket No. 38772,30 the

15           Commission modified its treatment of the CWIP-related portion of the

16           asset, ruling in Finding of Fact 15A: “in accordance with P.U.C. SUBST. R.

17           25.72(g) the portion of the pension prepayment asset included in CWIP

18           shall accrue allowance for funds used during construction beginning as of

19           the date of the changed rates in this docket.” The CWIP-related portion of

20           the Company’s pension asset ($25,311,236 out of the total asset) should

21           receive the same treatment, should the Commission reject the Company’s

     29
          Application of AEP Texas Central Co. for Authority to Change Rates.
     30
          Remand of Docket No. 33309 (Application of AEP Texas Central Company For Authority to
          Change Rates.



                                                                                            27
     Entergy Texas, Inc.                                                   Page 25 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1           primary position that the entire asset should be included in rate base as

2           Company supplied capital that reduces the pension costs otherwise

3           included in customer rates.

4

5                              E.      Property Insurance Reserve

6    Q.     MR. POUS HAS RECOMMENDED SEVERAL REDUCTIONS TO RATE

7           BASE FOR THE PROPERTY INSURANCE RESERVE. DO YOU AGREE

8           WITH HIS RECOMMENDATIONS?

9    A.     No.    Company witness Shawn Corkran will address Mr. Pous’ claims

10          regarding the 1997 ice storm; Company witness Greg Wilson addresses

11          the requested level of the storm accrual. I will address the balance of Mr.

12          Pous’ recommendations for reductions to the storm reserve balance.

13

14   Q      MR. POUS OBJECTS TO THE $12,498,325 STORM RESERVE

15          RECLASSIFICATION AS A RESULT OF THE JURISDICTIONAL

16          SEPARATION OF EGSI INTO ETI AND EGSL. PLEASE EXPLAIN THIS

17          RECLASSIFICATION.

18   A.     An analysis of the storm reserve charges was performed prior to the

19          jurisdictional separation to determine if the storm charges were incurred

20          for Louisiana or Texas property. The reclassification was made as a result

21          of this analysis to properly reflect the state in which the storm charges

22          were incurred. See page 25 of Exhibit MPC-R-3 for this analysis.




                                                                                     28
     Entergy Texas, Inc.                                                  Page 26 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1    Q.     MR. POUS RECOMMENDS A $10.95 MILLION REDUCTION TO THE

2           RESERVE BALANCE FOR WHAT HE DEEMS TO BE A $50,000

3           DEDUCTIBLE, WHICH HE RETROACTIVELY APPLIED TO PAST

4           STORMS. IS THIS REDUCTION APPROPRIATE?

5    A.     No. The $50,000 threshold has been consistently used by the Company

6           to designate a storm that will accumulate costs to be charged to the storm

7           reserve. A storm whose total costs are estimated to be less than $50,000

8           would be treated as normal O&M costs and not charged to the reserve.

9           This was never intended to be a “deductible” amount and is called “Major

10          Storm Damage Threshold” in Entergy’s current storm damage policy.

11          That policy is provided in the Company’s response to Cities’ RFI 6-2,

12          attached as my Exhibit MPC-R-3. The fact that these costs have been

13          charged to the reserve and not to O&M means these costs have never

14          been reflected in base rates. To retroactively make this adjustment as

15          proposed by Mr. Pous would be inconsistent with past base rate case

16          treatment and result in a permanent disallowance of these storms costs. If

17          such a policy change from a threshold to a deductible should be made, it

18          would need to be made on a prospective basis so that the amounts

19          charged to reserve and normal O&M would be reflected in the on-going

20          cost level.




                                                                                    29
     Entergy Texas, Inc.                                                   Page 27 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1    Q.      HAVE YOU REVIEWED MR. POUS’ DEPOSITION IN THIS DOCKET?

2    A.      Yes. During the line of questions asked of Mr. Pous regarding Docket No.

3            16705 and the rationale for adjusting for 219 storms since that time. Mr.

4            Pous seems to imply that the Company has a different storm damage

5            policy than was in place during the Docket No. 16705 test year.31

6

7    Q.      CAN      YOU     PROVIDE        EVIDENCE   THAT   THE    SAME       $50,000

8            THRESHOLD WAS A COMPONENT OF THE STORM DAMAGE POLICY

9            IN EFFECT FOR THE ENTIRE DOCKET NO. 16705 TEST YEAR?

10   A.      Yes. Please refer to Exhibit MPC-R-4.

11

12   Q.      DOES ANY ENTERGY COMPANY HAVE A DEDUCTIBLE?

13   A.      Yes. Entergy Mississippi moves the first $250,000 charged to the reserve

14           each year to O&M expense as outlined in the “Storm Damage Deductible”

15           section of Entergy’s storm damage policy.

16

17   Q.      MR. POUS CONTENDS THAT BY NOT HAVING A DEDUCTIBLE,

18           ENTERGY IS DOUBLE RECOVERING THE AMOUNTS. IS THIS TRUE?

19   A.      No. The costs that are charged to the reserve are only recovered once

20           through the storm damage accrual. They are not also charged to O&M

21           expense to be recovered twice.



     31
          Pous, Docket No. 39896 deposition at 93-95.



                                                                                      30
     Entergy Texas, Inc.                                                Page 28 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1    Q.     MR. POUS RECOMMENDS RAISING THE MINIMUM THRESHOLD FOR

2           STORM RESERVE CHARGES TO $500,000 FROM $50,000. DO YOU

3           AGREE WITH MR. POUS’ RECOMMENDATION?

4    A.     No. As I note above, the $50,000 storm minimum has been consistently

5           applied by the Company and there is no basis for a change. Furthermore,

6           the storm reserve charges at issue should be recovered in either O&M or

7           through the storm reserve. Mr. Pous’ recommendation, however, would

8           result in the recovery through neither of these avenues.   If Mr. Pous’

9           recommendation is adopted, then more of the Company’s storm costs will

10          be charged to normal O&M instead of the storm reserve. Mr. Pous does

11          not recommend the necessary increase to normal O&M for those storm

12          costs that are less than $500,000.    By failing to do so, he is, again,

13          recommending no recovery at all of reasonable, actual storm-related

14          costs.

15

16   Q.     HOW MUCH WOULD NORMAL O&M HAVE TO BE INCREASED TO

17          REFLECT MR. POUS’ RECOMMENDATION?

18   A.     The test year level of storms under $500,000 that would be charged to

19          normal O&M instead of the storm reserve is $1,532,000. If Mr. Pous’

20          recommended $500,000 minimum is adopted, O&M would need to

21          increase by $1,532,000.




                                                                                  31
     Entergy Texas, Inc.                                                    Page 29 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1    Q.     MR. POUS AND OPUC WITNESS NATHAN BENEDICT BOTH SAY ETI

2           SHOULD HAVE REASONABLY ANTICIPATED THESE STORM COSTS.

3           DO YOU AGREE?

4    A.     No.     As shown on Exhibit MPC-R-3, the annual expenditures are

5           extremely variable. Moreover, they are unpredictable as to timing. As

6           such, the level of expenses could not reasonably be anticipated.

7

8    Q.     MR. BENEDICT SAYS THAT SOME LEVEL OF MAINTENANCE

9           EXPENSE IS INCLUDED IN BASE RATES AND ONLY INCREMENTAL

10          AMOUNTS SHOULD BE CHARGED TO THE RESERVE.                          DO YOU

11          AGREE?

12   A.     No. The Company has been consistent in charging all costs related to

13          major storm work to the storm reserve. Base rates reflected only costs

14          charged to normal O&M in a test year. This would not include the costs

15          charged to the storm reserve in the test year. If the costs related to major

16          storm work had not been charged to the storm reserve, base rates for

17          normal O&M expense would have been higher.

18

19                         F.     Payroll and Incentive Compensation

20   Q.     WHAT ISSUES DO YOU ADDRESS IN THIS SECTION OF YOUR

21          REBUTTAL TESTIMONY?

22   A.     I will address issues raised by Mr. Garrett and Ms. Givens regarding

23          payroll.



                                                                                      32
     Entergy Texas, Inc.                                                  Page 30 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1    Q.     PLEASE        COMMENT         FIRST   ON   MR.   GARRETT’S     PAYROLL

2           ADJUSTMENT.

3    A.     Mr. Garrett states the Company’s proposed adjustment includes a wage

4           increase nine months after the test year but omits workforce changes and

5           changes in salary mix. The Company’s requested level of payroll began

6           with the test year payroll and was increased for known and measurable

7           changes in compliance with PUCT Substantive Rule 25.231(b). These

8           changes were for known wage increases stipulated in the bargaining

9           contracts and for a board approved non-bargaining wage increase

10          effective April 1, 2012.       Rather than simply adjusting for known and

11          measurable changes to the Company’s test year historical expense, Mr.

12          Garrett also proposes applying a productivity statistic to determine

13          recoverable payroll expense.

14

15   Q.     DOES MR. GARRETT’S PRODUCTIVITY ADJUSTMENT COMPLY WITH

16          SUBSTANTIVE RULE 25.231(b)?

17   A.     No. His productivity adjustment is not a known and measurable change

18          specific to the Company’s test year payroll.

19

20   Q.     WHY IS IT NOT KNOWN AND MEASURABLE TO THE COMPANY?

21   A.     Mr. Garrett quotes national averages for productivity indices and assumes

22          they are reasonable and representative of the Company’s productivity. By




                                                                                    33
     Entergy Texas, Inc.                                                    Page 31 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1           the very nature of averages, some companies are much above and some

2           are much below the average.

3

4    Q.     DOES MR. GARRETT PROVIDE ANY STUDIES THAT CONFIRM HIS

5           2.1% PRODUCTIVITY ADJUSTMENT IS APPLICABLE IN THIS CASE?

6    A.     No. He has not provided any study to show that his percentage in any

7           way applies to the Company in this case.

8

9    Q.     MR. GARRETT STATES THE COMPANY CHOSE TO UPDATE

10          PAYROLL FOR THE APRIL 1, 2012 INCREASE BUT DID NOT UPDATE

11          THE     FILING     FOR      OTHER     ITEMS   SUCH   AS   ACCUMULATED

12          DEPRECIATION AND ACCUMULATED DEFERRED INCOME TAX. DO

13          YOU AGREE?

14   A.     No.    The Company has adjusted for known and measurable changes.

15          Rate base items such as those he references cannot, by rule, be updated

16          past the test year.

17

18   Q.     DOES MR. GARRETT PROPOSE ANY OTHER CHANGES TO THE

19          COMPANY’S PAYROLL?

20   A.     Yes. Mr. Garrett cites the Company’s response to Cities’ RFI 18-8(b),

21          which shows the 2010 base salary is 1.8% above the market median.

22          Based on this, he reduces the test year base payroll by 1.8%.




                                                                                      34
     Entergy Texas, Inc.                                                   Page 32 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1    Q.     DO YOU AGREE WITH THIS ADJUSTMENT?

2    A.     No. Company witness Kevin G. Gardner states on page 23 of his direct

3           testimony that “Towers Watson provides competitive analysis of the

4           Entergy Companies’ executive compensation to the market and support

5           for the Entergy Companies’ approach that a value between 90% and

6           110% of the median level of compensation is “at market.” In fact, Towers

7           Watson stated in its 2010 Competitive Compensation Analysis that

8           because of differing job duties, individual characteristics, and experience

9           levels, Towers Watson believes that a company's pay levels are

10          competitive if they fall between 85% and 115% of the marketplace”.      Mr.

11          Garrett ignores the fact that Towers Watson considers “at market” to be a

12          10-15% spread from median.            ETI was well within this spread and,

13          therefore, Mr. Garrett’s adjustment is not appropriate.

14

15   Q.     DO YOU AGREE WITH MR. GARRETT’S PROPOSED PAYROLL

16          ADJUSTMENTS?

17   A.     The Company’s payroll adjustment is the more appropriate approach to

18          establishing test year payroll expense, and Mr. Garrett’s recommendations

19          should be rejected.

20

21   Q.     PLEASE COMMENT ON MS. GIVENS’ PAYROLL ADJUSTMENT.

22   A.     I have reviewed her adjustment and, for the most part, I agree with her

23          findings. However, Ms. Givens used different headcounts for the end of



                                                                                     35
     Entergy Texas, Inc.                                                     Page 33 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1           the test year for ETI and ESI than are appropriate and included in my

2           payroll adjustment.       The Company’s payroll adjustment reduced ETI

3           headcount to 675 and ESI headcount to 3,054. Ms. Givens’ adjustment

4           begins with end of the test year ETI headcount of 678 and ESI headcount

5           of 3,055 which caused a double counting of three ETI and one ESI

6           employee. These four employees are already reflected in my adjustment.

7           I also corrected an error in the ESI benefits calculation.       Ms. Givens

8           inadvertently used the ETI percentage in the calculation rather than the

9           ESI percentage shown on her exhibit.         I also do not agree with the

10          calculation of the savings plan adjustment or the calculation of the full time

11          equivalents.

12

13   Q.     PLEASE EXPLAIN WHY YOU DO NOT AGREE WITH THE SAVINGS

14          PLAN LOADER CALCULATION.

15   A.     Ms. Givens inappropriately applied both the benefits and savings plan

16          loader percentages to the headcount adjustment.

17

18   Q.     HOW SHOULD THE SAVINGS PLAN LOADER BE CALCULATED?

19   A.     The savings plan loader should not be calculated on the headcount

20          change because it is already included in the benefits loader rate and

21          should not be applied to the headcount change again.




                                                                                       36
     Entergy Texas, Inc.                                                     Page 34 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1    Q.     HOW      WOULD        YOU     CHANGE    THE   FULL    TIME    EQUIVALENT

2           CALCULATION?

3    A.     Ms. Givens assumed that part time employee’s average salary is 50% of

4           the full time average salary. Responses to Cities’ RFI 12-6 and 12-7 allow

5           for the calculation of the actual part time average salary by providing the

6           test year wages and monthly headcounts. Ms. Givens relied on Staff RFI

7           7-4 for part time headcount, which consists of part time headcount of 35

8           and temporary employee headcount of 39 for a total of 74 instead of 73.

9           Exhibit MPC-R-3 is a correct calculation of full time equivalents.

10

11   Q.     HOW DO THESE CHANGES AFFECT MS. GIVENS’ ADJUSTMENT?

12   A.     Her ETI headcount adjustment (AG-7) has overstated her O&M payroll

13          reduction by $224,217.          Her ESI headcount adjustment (AG-7) has

14          understated her O&M payroll increase by $37,531.           Exhibit MPC-R-1

15          shows the ETI calculation and Exhibit MPC-R-2 shows ESI calculation.

16

17   Q.     DO YOU AGREE WITH MS. GIVENS’ INCENTIVE COMPENSATION

18          PAYROLL TAX ADJUSTMENT?

19   B.     No.     She calculated FICA at 7.65% on the Staff adjustments to all

20          incentive plans. The executive plans (Executive Annual Incentive Plan,

21          Restricted Stock Incentive, Long-Term Incentive Plan, Restricted Share

22          and Equity Awards) include only highly compensated executives that are




                                                                                       37
     Entergy Texas, Inc.                                                    Page 35 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1           predominantly over the limit for the social security portion of FICA and are

2           only subject to the 1.45% Medicare component of FICA.

3

4    Q.     HAVE YOU REVISED MS. GIVENS’ PAYROLL TAX ADJUSTMENT

5           CALCULATIONS?

6    A.     Yes. I applied the entire 7.65% FICA rate to the non-executive incentive

7           plans (Management Incentive Plan, Exempt Incentive Plan, Teamshare

8           Incentive Plan, and the Teamshare Bargaining Incentive Plan) and only

9           the Medicare component (1.45%) on the executive plans. Ms. Givens’ ETI

10          payroll tax adjustment is overstated by $15,933 and is summarized in

11          Exhibit MPC-R-4. Ms. Givens’ ESI payroll tax adjustment is overstated by

12          $269,362 and is summarized in Exhibit MPC-R-5.

13

14                                       G.       DSM Costs

15   Q.     OPUC        WITNESS         DR.       CAROL   SZERSZEN     RECOMMENDS

16          DISALLOWING ONE HALF ($171,032) OF ETI’s PROJECT CODE

17          F3PPE9981S TEST YEAR COSTS BECAUSE SHE STATES THAT SHE

18          WAS UNABLE TO DETERMINE HOW MUCH OF THIS PROJECT’S

19          COSTS PERTAINED TO ENERGY EFFICIENCY, DSM, AND SUPPLY

20          SIDE INITIATIVES, WHICH SHE ASSERTS SHOULD BE RECOVERED

21          THROUGH          THE      COMPANY’S        ENERGY   EFFICIENCY        COST

22          RECOVERY FACTOR RIDER (“EECRF”). DO YOU AGREE WITH THIS

23          ADJUSTMENT?



                                                                                      38
     Entergy Texas, Inc.                                                   Page 36 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1    A.      No. As addressed in Company witness Phillip R. May’s rebuttal testimony,

2            this project code captures the cost of general activities of the Company’s

3            Integrated Energy Management department and are not included in the

4            Company’s EECRF rider. Because these are not costs that must be, or

5            are currently being recovered through the EECRF, they are not double

6            recovered and should be included in the Company’s cost of service.

7

8                                       H.        MSS-2 Costs

9    Q.      PLEASE COMMENT ON CITIES’ WITNESS DENNIS W. GOINS’ MSS-2

10           ADJUSTMENT.

11   A.      Mr. Goins recommends that the MSS-2 expense level in this docket be set

12           to the twelve months ended December 31, 2011 level of $4,370,600 and

13           then adjusted for load growth.32 Company witness Pat Cicio will discuss

14           the load growth adjustment that Mr. Goins proposes. I will address the

15           appropriate level of MSS-2 expense only.

16

17   Q.      DO YOU AGREE WITH MR. GOINS’ MSS-2 ADJUSTMENT?

18   A.      No.   Mr. Goins’ recommended expense level is based on the twelve

19           months ended December 31, 2011 expense and as such does not

20           recognize a full year’s effect of ongoing equalizable transmission

21           investment or the change in responsibility ratios.



     32
          Goins HSPM WP/MSS-2-dg.xls.



                                                                                     39
     Entergy Texas, Inc.                                                       Page 37 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1    Q.     IS THERE ANY OTHER INFORMATION THAT SUPPORTS YOUR

2           OPINION THAT THE TWELVE MONTHS ENDED DECEMBER 31, 2011

3           EXPENSE IS NOT APPROPRIATE TO USE IN CALCULATING THE

4           RATE YEAR LEVEL OF MSS-2 EXPENSE?

5    A.     Yes. Mr. Goins’ own workpapers show that the monthly MSS-2 expense

6           has increased over 62% between January 2011 ($235,205) and

7           December 2011 ($624,352).             This fact supports that the twelve months

8           leading up to the December 2011 expense level do not reflect a

9           reasonable MSS-2 expense level to include in the cost of service.

10

11   Q.     HAVE YOU CALCULATED A MORE APPROPRIATE EXPENSE LEVEL

12          ASSUMING THE COMMISSION DOES NOT AGREE WITH THE

13          COMPANY’S PRO FORMA ADJUSTMENT FOR RATE YEAR MSS-2

14          EXPENSE?

15   A.     Yes. It is more appropriate to set the MSS-2 expense level based on the

16          most current month’s expense times twelve, assuming the Commission

17          does not grant the Company’s original request. The February 2012 Intra-

18          System Bill (“ISB”) indicates that ETI had monthly MSS-2 expense of

19          $698,290; therefore, the annual MSS-2 expense that should be included in

20          the cost of service is $8,379,480.




                                                                                         40
     Entergy Texas, Inc.                                                      Page 38 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1    Q.       IS    THE         COMPANY    RECOMMENDING         THE   $8,379,480   MSS-2

2             EXPENSE LEVEL YOU HAVE CALCULATED?

3    A.       No. It is appropriate to set the MSS-2 expense level in the docket to the

4             rate year level. As further explained by Company witness Mark McCulla,

5             this level is based on known and measurable equalizable transmission

6             investments that are appropriately included in the calculation of projected

7             MSS-2 expense and should be approved.

8

9                                  I.     Nuclear Decommissioning

10   Q.       PLEASE COMMENT ON MR. GARRETT’S RECOMMENDATION TO

11            REDUCE THE ANNUAL REVENUE REQUIREMENT FOR THE 70%

12            REGULATED RIVER BEND NUCLEAR STATION FROM $2,019,000 TO

13            $1,126,000 AS PROVIDED IN THE COMPANY’S RESPONSE TO

14            CITIES’ RFI 10-22. DO YOU AGREE WITH THIS ADJUSTMENT?

15   A.       No. First, the $2,019,000 stipulated in the Commission’s Final Order for

16            Docket No. 37744 was approved quite recently, on December 13, 2010.

17            Secondly, Mr. Garrett notes that PUCT Substantive Rule 25.231(b)(F)(i)

18            states that the annual cost of decommissioning for ratemaking purposes

19            must be determined and expressly included in the COS established by the

20            Commission’s order.         Staff witness Slade Cutter’s testimony, however,

21            correctly points out that the Company is in compliance with this rule.33

22            The Company submits that the current $2,019,000 level of annual

     33
          Cutter Direct at 6.



                                                                                        41
     Entergy Texas, Inc.                                                        Page 39 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1           decommissioning expense represents the most current information

2           reasonably available, based upon the August 9, 2011 Nuclear Regulatory

3           Commission letter (included in my direct testimony as Exhibit MPC-2),

4           which approves that amount as meeting the required minimum funding

5           criteria based on current funding level, length of time remaining on the

6           license, expected earnings on the trust fund, and future collections to the

7           trust fund. It should not be the policy of the Commission to inject volatility

8           into the rate of decommissioning expense recovery, which can impact the

9           minimum funding level based on fluctuations of calculation factors over

10          short periods of time.

11

12   Q.     WHY DO YOU SAY THAT IT SHOULD NOT BE THE COMMISSION’S

13          POLICY TO INJECT VOLATILITY INTO THE ANNUAL RATE OF

14          DECOMMISSIONING EXPENSE RECOVERY?

15   A.     Substantive Rule 25.231(b)(F)(iii) & (iv) notes that in the event a utility

16          does not file a rate case within a five year period (which the Company

17          has), the utility must perform a study or redetermination of the previous

18          study and file it with the Commission. The Company submits that this five

19          year    requirement      reflects     the   Commission’s   recognition   that   a

20          normalization of decommissioning expense recovery over a reasonable

21          extended period of time is in the best interest of the customer by

22          normalizing the swings that otherwise might occur in more frequent

23          decommissioning expense requirement calculations.



                                                                                            42
     Entergy Texas, Inc.                                                   Page 40 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896




1    Q.     WHAT DOES THE COMPANY RECOMMEND THE COMMISSION

2           ORDER REGARDING THIS MATTER?

3    A.     Consistent with the position of Commission Staff, the Company

4           recommends that the Commission reject Mr. Garrett’s recommendation

5           and approve that the most recent Commission-approved level of annual

6           decommissioning expense remain unchanged at $2,019,000.

7

8                                       J.        Depreciation

9    Q.     WHAT DEPRECIATION ISSUES WILL YOU ADDRESS IN THIS

10          SECTION OF YOUR REBUTTAL TESTIMONY?

11   A.     I will address certain contentions presented by Mr. Pous in Section IV of

12          his direct testimony;

13          1.      pages 7-8 regarding generating unit life span,

14          2.      pages 39-45 regarding fully accrued depreciation,

15          3.      pages 14-15 regarding positive net salvage on power plants, and

16          4.      pages 25-26 regarding suggested problems with the Company’s

17                  accounting procedure for the booking of cost of removal.




                                                                                      43
     Entergy Texas, Inc.                                                     Page 41 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1                                             Plant Lives

2    Q.      WHAT IS MR. POUS’ POSITION REGARDING GENERATING UNIT LIFE

3            SPAN?

4    A.      Mr. Pous insinuates on page 7, lines 1-9 of his direct testimony that the

5            Company has routinely attempted to misstate the life expectancy of its

6            generating units. Mr. Pous bases his opinion on his representation of the

7            Company’s position in two rate cases.34

8

9    Q.      IS MR. POUS WRONG IN HIS REPRESENTATION?

10   A.      Yes. The Company has always attempted to present its best estimate of

11           when generating units would be retired based on the facts and

12           circumstances every time it has filed a depreciation study with a rate

13           proceeding. In those situations where no depreciation study is presented

14           by the Company, it reports the retirement dates underlying the

15           depreciation rates in the case as last approved.          There is nothing

16           nefarious in the Company’s practice in either regard.        The Company

17           respects Mr. Pous’ ability to make his determinations of his estimated life

18           spans. It is unfair of Mr. Pous to not pay the Company the same due

19           respect regarding life spans, as it is always a contentious issue in every

20           regulatory proceeding without regard to the basis of either position.

21                  Finally, the Company has proposed different plant retirement dates

22           for depreciation purposes in this proceeding than those previously

     34
          PUCT Docket Nos. 16705 and 37744.



                                                                                       44
     Entergy Texas, Inc.                                                    Page 42 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1             proposed. For some units, the depreciation retirement dates are sooner

2             than previously presented, and for others the depreciation retirement

3             dates are further out that previously presented. None of the information

4             presented in this proceeding represents an attempt by the Company to

5             “underestimate the life spans for its various generating units”.35 What it

6             does represent is the Company’s best estimate of a responsible and

7             reasonable estimate of an uncertain event for a determination of when

8             depreciation expense should cease to be accrued on an asset. Mr. Pous

9             opposed only one of the several plant life spans proposed by the

10            Company (relating to the Sabine Plant Units 4 and 5).

11

12   Q.       WHO IS PRESENTING INFORMATION TO SUBSTANTIATE THE

13            COMPANY’S PROPOSED RETIREMENT DATES FOR DEPRECIATION

14            PURPOSES?

15   A.       An explanation of the basis for the Sabine Units’ retirement date and

16            impact of operating and maintaining generating units on the life span of

17            the Sabine Units is discussed in the rebuttal testimony of Company

18            witnesses Winfred W. Garrison and Cooper and their testimony supports

19            the Company’s position regarding the expected life span of the Sabine

20            Units for the determination of depreciation accruals.




     35
          Exhibit JP-1 at 7, line 3.



                                                                                      45
     Entergy Texas, Inc.                                                      Page 43 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1                               K.      Fully Accrued Depreciation

2    Q.     WHAT IS MR. POUS’ POSITION REGARDING FULLY ACCRUED

3           DEPRECIATION?

4    A.     As I understand it, Mr. Pous has presented a new regulatory theory

5           claiming that there must be an exact matching of the level of depreciation

6           expenses recovered under previously authorized electric utility rates and

7           current revenues. His theory is that depreciation expenses, unlike other

8           expense items originally included in the determination of utility rates, are in

9           some way a permanent component of revenues from the moment electric

10          utility rates are set until such rates are re-determined in some future rate

11          case and if any item in plant in service remains in plant in service beyond

12          the point that its service value is fully amortized, depreciation expense

13          should continue to be accrued. Another way of stating his position could

14          be that Mr. Pous has determined that the setting of rates creates an exact

15          recovery mechanism that requires periodic true up.           It is difficult to

16          determine which theory he is espousing. Regardless, Mr. Pous ultimately

17          erroneously concludes that ETI has reset its approved depreciation rates

18          to zero without regulatory approval.

19                  What Mr. Pous has failed to recognize is that time passes and that

20          all costs change, as do all other factors that initially formed the

21          determination of historical electric utility rates. In addition, Mr. Pous has

22          presented an opinion that is not in concert with the Uniform System of

23          Accounts (“USoA”) as it is written.



                                                                                        46
     Entergy Texas, Inc.                                                     Page 44 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896




1    Q.     WHY IS MR. POUS’ THEORY IN ERROR?

2    A.     Depreciation is calculated and designed to reflect an asset’s loss in

3           service value over time. Ideally, that time period is the life span of the

4           asset being depreciated and the asset would neither be under-accrued at

5           the time it is retired nor over-accrued prior to its retirement. Estimates are

6           imperfect by their very nature.       It is virtually impossible to precisely

7           determine what date units will be retired and what the cost of retirement

8           will be at that time. As such, estimates must be employed and periodically

9           revised as more information becomes available.

10

11   Q.     WHAT IS SERVICE VALUE?

12   A.     Service value is defined in the USoA as the original cost of plant less net

13          salvage. Net salvage is defined in the USoA the cost of removing plant

14          from service (“cost of removal”) less any proceeds realized upon its

15          disposition (“salvage”).       When cost of removal exceeds salvage, net

16          salvage is negative, and when salvage exceeds cost of removal, net

17          salvage is positive.      Once that service value has been fully amortized

18          through the application of the depreciation rate(s) most recently approved

19          by the regulator, there is no further loss in service value to be recognized

20          unless and until the regulator determines that other factors require further

21          evaluation.     The other factors would be the incurred cost of removal




                                                                                       47
     Entergy Texas, Inc.                                                          Page 45 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1           versus the cost of removal underlying the depreciation rate and the

2           realized salvage versus the salvage underlying the depreciation rate.

3

4    Q.     ARE THERE OTHER CONSIDERATIONS?

5    A.     Yes.     The Company constantly adds, removes, retires, and replaces

6           various assets and components of assets between rate cases. It does

7           not, however, defer the depreciation expense on the new plant additions

8           for future recovery, nor does it “unilaterally” continue to recognize

9           depreciation on assets where the service value has been fully

10          depreciated. Neither accounting procedure is appropriate for purposes of

11          recording depreciation expense.

12

13   Q.     HAS THE COMPANY CONSISTENTLY ADHERED TO THE PRINCIPLE

14          THAT DEPRECIATION CEASES ONCE THE SERVICE VALUE OF

15          ASSETS ARE FULLY AMORTIZED?

16   A.     Yes. That has been the Company’s policy for as long as I am aware.

17

18   Q.     DO ANY OF ENTERGY’S OTHER REGULATORS ADHERE TO

19          MR. POUS’ POSITION ON THIS ITEM?

20   A.     Not that I am aware of. In fact, APSC General Staff witness Ms. Gayle

21          Freier stated on page 24, lines 3 through 5 of her direct testimony in the

22          recent    APSC      Docket     No.    09-084-U,   “For   ratemaking    purposes,

23          depreciation expense should not be calculated on any account with a



                                                                                            48
     Entergy Texas, Inc.                                                   Page 46 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1           reserve ratio equal to or exceeding 100% unless the account has a

2           negative salvage value.”          In that section of her testimony she was

3           discussing the calculation of depreciation expense on 22 accounts that

4           were fully amortized. Of the 22 accounts Ms. Freier identified, Entergy

5           Arkansas had stopped depreciating 20 prior to the date of filing (some as

6           early as 2005).

7

8    Q.     WHAT RECENT EVENTS HAVE OCCURRED TO MAKE THIS ISSUE

9           RELEVANT TO ETI?

10   A.     Two things have occurred. First, ESI put into place a new fixed-asset

11          accounting system in 2005 that enables ESI and the Entergy Operating

12          Companies to automate processes previously handled manually, such as

13          stopping the recording of depreciation expense when service value is fully

14          amortized. The second thing that occurred is that three accounts became

15          fully amortized since ETI’s last rate case.      Neither of these things is

16          abnormal, nor do they change any company policy concerning

17          depreciation.

18

19   Q.     ARE THE COMPANY’S ACTIONS IN ANY MANNER CONTRARY TO

20          ANY ORDERS OR REQUIREMENTS OF THE PUCT?

21   A.     Not at all.     The Company has continued at all times to observe the

22          Commission approved depreciation rates and to accrue depreciation

23          expense consistent with Commission rules and the FERC USoA.



                                                                                     49
     Entergy Texas, Inc.                                                    Page 47 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896




1    Q.     IS THERE ANYTHING ELSE THE COMMISSION SHOULD CONSIDER

2           ON THIS MATTER?

3    A.     Yes. First, depreciation expense accruals are only suspended so long as

4           the account is fully amortized. In other words, if a subsequent addition

5           occurs to the account in the future, depreciation will begin to be accrued

6           anew even though that item is not “in base rates” through the application

7           of approved depreciation rates.       The Company does not defer that

8           depreciation until the next rate case. Second, the Company’s depreciation

9           accounting is subject to independent external audit, and the Company’s

10          external auditors would not allow the Company to “unilaterally cease”

11          depreciation expense accrual if such action required regulatory approval;

12          nor would they allow ETI to “unilaterally” continue to accrue depreciation,

13          as suggested by Mr. Pous, without specific expressed regulatory approval.

14

15   Q.     WHY WOULD THE COMPANY’S EXTERNAL AUDITORS REJECT AN

16          ATTEMPT        BY     THE     COMPANY   TO   CONTINUE      TO     ACCRUE

17          DEPRECIATION EXPENSE ON FULLY DEPRECIATED ACCOUNTS?

18   A.     It would be a violation of Generally Accepted Accounting Principles

19          (“GAAP”) to continue to record depreciation expense on items which are

20          fully depreciated.       The external auditors must also present a CPA

21          Certification Statement at the beginning of the Company’s FERC Form 1

22          which should:



                                                                                      50
     Entergy Texas, Inc.                                                             Page 48 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1                     a) Attest to the conformity, in all material aspects, of the
2                     below listed (schedules and pages) with the Commission’s
3                     applicable Uniform System of Accounts (including applicable
4                     notes relating thereto and the Chief Accountant’s published
5                     accounting releases).36
6

7    Q.       HAS THE COMPANY VIOLATED ANY REGULATORY PRINCIPLE AS

8             SUGGESTED BY MR. POUS?

9    A.       No. However, the refund of under-accrued depreciation expense as Mr.

10            Pous recommends would constitute retroactive ratemaking.

11

12                                          L.      Net Salvage

13   Q.       WHAT IS MR. POUS’ POSITION REGARDING NET SALVAGE OF

14            EXISTING GENERATING UNITS?

15   A.       Mr. Pous has suggested that negative salvage is inappropriate for existing

16            generating facilities.      His recommendation is contrary to long standing

17            practice of the PUCT to provide for a negative salvage value that

18            represents terminal salvage of regulated utility generating units. I will not

19            address the general issue of negative salvage as that will be addressed by

20            Company witness Dane A. Watson. What I will address is the suggestion

21            in Mr. Pous’ testimony on pages 14-15 that the Company received a

22            “substantial positive net salvage”37 due to the retirement of Neches Station

23            and Nelson Generating Units 1 and 2 and those transactions are a

24            reasonable representation of probable future events.

     36
          Instructions for filing FERC Form Nos. 1 and 3-Q, Paragraph III, (d) a).
     37
          Direct Testimony of Mr. Pous, page 14 line 24.



                                                                                               51
     Entergy Texas, Inc.                                                     Page 49 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896




1    Q.     HAS MR. POUS PROVIDED ANY INFORMATION REGARDING THE

2           EVENTS SURROUNDING THE NECHES STATION GENERATING

3           UNITS?

4    A.     He has not. Mr. Pous cites Neches Station on page 14, lines 24 and 25 of

5           his direct testimony but presents no specific information regarding the

6           facts surrounding that facility.      A discussion of those specific facts,

7           however, is essential to understanding why the salvage associated with

8           the Neches Station provides no support for Mr. Pous’ position.

9

10   Q.     WHAT ARE THE FACTS REGARDING THE FACILITY?

11   A.     Neches Station was a generating station in Beaumont, Texas that was

12          built between 1926 (Unit 1) and 1959 (Unit 8).         Units 1 and 2 (total

13          capacity 57 MW) were retired and dismantled in 1966 at no additional cost

14          to the customer or to the Company. The boiler for Unit 7 exploded in

15          1983. The Company subsequently retired that unit as a result of that

16          incident.    The Company received an insurance reimbursement for that

17          facility. The insurance reimbursement was in excess of the net book value

18          of the entire station. The benefit of that insurance reimbursement above

19          the original cost of Neches Unit 7 was refunded to the customer through a

20          subsequent rate action. The remaining generating units were placed in

21          long term storage in 1985. The remaining units were demolished in 2002

22          and 2003 at a net cost of $14.491 million. The Company sought recovery



                                                                                       52
     Entergy Texas, Inc.                                                   Page 50 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1           of the negative salvage costs through amortization in PUCT Docket No.

2           34800.

3

4    Q.     DOES THIS FACT PATTERN SUPPORT MR. POUS’ CONTENTION?

5    A.     No. It is unreasonable to predicate a positive salvage value based on a

6           boiler explosion, particularly when customers received the benefit of the

7           excess insurance reimbursement, and the Company ultimately incurred a

8           considerable cost for dismantling the Neches Station facility. These facts

9           are obviously quite unique and atypical, and not indicative of normally

10          recurring retirement activity.

11

12   Q.     WHAT ARE THE FACTS REGARDING NELSON UNITS 1 AND 2?

13   A.     Nelson Units 1 and 2 were situated adjacent to an industrial complex, and

14          thus uniquely situated to enable industrial customers near the site to form

15          a joint venture that would acquire two of the units at Nelson Station (83%

16          depreciated at the time) to convert into a co-generation facility. Those

17          facilities were substantially reconfigured (converted to a Fluidized Bed

18          Combustion heat source) at the cost of the industrial participants in the

19          Joint Venture.      The gain on the transaction was passed through to

20          customers in subsequent rate actions.




                                                                                     53
     Entergy Texas, Inc.                                                     Page 51 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1    Q.     WOULD THIS UNIQUE SITUATION BE LIKELY TO OCCUR AGAIN?

2    A.     I do not know. However, such a unique set of circumstances has not

3           repeated itself at any of ETI’s facilities in the last 24 years. Nor has such

4           a set of circumstances ever occurred at any Entergy Operating Company

5           facility other than the two Nelson units.    Lastly, what I do know from

6           internal discussions is that the units were largely depreciated and

7           inoperable without significant modification (such as the modification

8           performed by the Joint Venture participants) and that most of the benefits

9           of the transaction were passed on to customers. It would be wrong in my

10          opinion to suggest that the Nelson situation is likely to recur or suggest

11          that it is reasonable to base a decision on whether to reflect negative

12          salvage in the production depreciation rates on the unique circumstances

13          of the Nelson 1 and 2 generating units.

14

15                           M.      Accounting For Removal Costs

16   Q.     WOULD YOU SUMMARIZE YOUR UNDERSTANDING OF MR. POUS’

17          STATEMENTS ON PAGES 25-25 OF HIS DIRECT TESTIMONY?

18   A.     Mr. Pous is suggesting that the Company’s books and records

19          inappropriately reflect the amounts of cost of removal incurred due to the

20          removal of distribution assets on projects where both additions to and

21          removals from plant in service are the purpose of the project.




                                                                                       54
     Entergy Texas, Inc.                                                  Page 52 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1    Q.     HOW DOES THE COMPANY RECORD COST OF REMOVAL OF

2           DISTRIBUTION FACILITIES ON ITS BOOKS AND RECORDS WHEN

3           PROJECTS INCLUDE BOTH ADDITIONS TO AND REMOVALS FROM

4           PLANT IN SERVICE?

5    A.     The Company allocates the incurred costs of such projects between

6           installation and removal based upon estimates prepared by engineers

7           using the Company’s Distribution Information System (“DIS”).          The

8           process of developing those estimates, including the development of “as

9           built” estimates is discussed in the rebuttal testimony of Company witness

10          Corkran.

11

12   Q.     HOW DOES THE ALLOCATION PROCESS WORK?

13   A.     Costs are aggregated on work orders in the Company’s accounting

14          systems and allocated between cost of removal and installation based on

15          the original estimated cost of the project until the project’s completion.

16          This ensures that the costs are reasonably reflected on the books in

17          FERC Accounts 107 (CWIP) and 108 (Accumulated Provision for

18          Depreciation as Retirement Work in Progress (“RWIP")). Upon completion

19          of the work request, the construction department enters field changes into

20          DIS’s AsBuilt screen after which DIS runs the final estimate which the

21          accountants refer to as an “as built estimate” that reflects actual items

22          installed and a standard cost of adding and removing the particular items

23          added and removed. The reason it is an estimate is because, primarily



                                                                                    55
     Entergy Texas, Inc.                                                     Page 53 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1           due to timing, the per unit rates in the estimate may not reflect the actual

2           hourly labor rates, transportation rates, or material costs. For instance,

3           the hourly labor rate standard may be $30 per hour whereas the individual

4           who performed the work would be a higher or lower rate than the

5           standard.

6                   Upon completion and receipt of the as built estimate into the

7           Company’s PowerPlant accounting system, the Company reflects a final

8           allocation of the actual non-material costs to installation and removal,

9           using the allocation percentages provided by the estimated non-material

10          costs. Material amounts and indirect costs such as AFUDC, Store Costs,

11          and Construction overheads are added to the amount of non-material

12          costs allocated to installation, and the installation costs are then closed to

13          plant in service. The residual calculated amount composed of direct labor,

14          labor loaders, transportation and transportation loaders is added to

15          remaining indirect costs accrued in RWIP and transferred to the reserve

16          by plant account. For instance, the estimated non-material costs on the

17          project discussed in the testimony of Company witness Corkran resulted

18          in a final ratio of the costs of roughly 86% to installation and 14% to

19          removal. This is before assignment of indirect costs such as construction

20          overheads, AFUDC, and Store Costs and Associated Stock (FERC

21          Account 163) or the inclusion of material costs in the total CWIP amount.

22          The final result was as follows:




                                                                                       56
     Entergy Texas, Inc.                                                    Page 54 of 55
     Rebuttal Testimony of Michael P. Considine
     Docket No. 39896


1           As built estimate:

2                   CWIP       $48,081      93%

3                   RWIP         $3,410      7%

4           Actual Cost including overheads:

5                   CWIP       $54,552      96%

6                   RWIP         $2,546      4%

7           The slight differences are driven by the addition of construction overheads

8           and AFUDC.

9

10   Q.     DO THE DIFFERENCES SUGGEST TO YOU THAT SOME FLAW

11          EXISTS IN THE PROCEDURE FOR ALLOCATION OF COSTS

12          BETWEEN INSTALLATION AND REMOVAL?

13   A.     No. The differences between the as built estimate provided by the DIS

14          and the final amounts booked to the Company’s property accounts reflect

15          the addition of AFUDC and other construction overhead allocation

16          amounts.      Those would be difficult to determine with any degree of

17          accuracy in a construction estimating system and would not drive the

18          results Mr. Pous suggests in his testimony.      The process is driven by

19          experts in estimating the activities for installing and removing distribution

20          utility property and there is no reason to believe that the accounting

21          process would result in amounts that were not representative of the actual

22          costs to remove distribution utility property.




                                                                                      57
    Entergy Texas, Inc.                                  Page 55 of 55
    Rebuttal Testimony of Michael P. Considine
    Docket No. 39896


1   Q.     DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY?

2   A.     Yes.




                                                                   58
                                                                                                                                                                                         Exhibit MPC-R-1
                                                                                                                                                                                        Docket No. 39896
                                                                                                                                                                                              Page 1 of 1
                                                                                               Entergy Texas, Inc.
                                                                                          MISO Transition Expenses
                                                                                         July 2011 through March 2012


                                                                                            Expenses by Account
                    Account and Description                     Jul-11       Aug-11         Sep-11      Oct-11          Nov-11        Dec-11        Jan-12        Feb-12          Mar-12      Totals
     4031AM - Deprec Exp billed from Serv Co                      12,584       17,439           (759)      5,274           7,248         7,931         3,065         7,192           6,904      66,879
     408110 - Employment Taxes                                      7,042       5,127          4,574       5,353           4,470         5,582         3,888         4,884           5,887      46,808
     500000 - Oper Supervision & Engineerin                           773         962          1,062         386            (128)          516           (11)         (115)            171       3,616
     506000 - Misc Steam Power Expenses                             1,001       1,836                                                      569                                                   3,406
     556000 - System Control & Load Disp.                             267       1,292           1,066          115             3            34                                          7        2,784
     557000 - Other Expenses                                           31           (9)           749           36           276           435            146          (261)          (99)       1,305
     560000 - Oper Super & Engineering                              2,553                         367           81           715           130             50           (63)          124        3,955
     561000 - Load Dispatching                                                                                                                            138          (270)          134             2
     561200 - Load Dispatch- transm system                         1,943          (730)         1,129          472           531            152           518          (171)          488        4,331
     561300 - Load disptch-transm serv & sch                         334                                         4            64            146                                                    548
     566000 - Misc. Transmission Expenses                            728         6,018           (169)                        74          1,460         4,768        (3,863)           240       9,257
     575100 - Regional Energy Mkts-Oper Supv                     (16,713)         (888)             0                                        17                                          2     (17,583)
     909000 - Information & Instruct Adv Ex                                                       103           90            (35)          745           (78)         (670)           304         458
     920000 - Adm & General Salaries                             128,451        83,682         76,235       90,436         73,950       119,792        62,735        86,326         92,317     813,925
     921000 - Office Supplies And Expenses                        16,869        26,316         (5,178)       9,024         16,083        16,989         2,732         3,096          4,664      90,594
     923000 - Outside Services Employed                          384,449       264,867         80,933      428,767       (112,530)    1,059,754        (4,757)       72,756         78,906   2,253,145
     924000 - Property Insurance Expense                           3,313          (398)                                                      (0)                                                 2,915
     926000 - Employee Pension & Benefits                         50,975        30,600         27,857       30,403        28,107         41,683        18,669        30,508         32,455     291,257
     928000 - Regulatory Commission Expense                        4,023         5,326          1,375          766         1,860         20,906           819        (3,228)            39      31,885
     930100 - General Advertising Expenses                         4,596         6,120            551          838           242            135                                                 12,482
     930200 - Miscellaneous General Expense                                                                                   34                                                                     34
     Totals                                                      603,221       447,559        189,894      572,044        20,964      1,276,976        92,681       196,121        222,544   3,622,005


                                                                                             Expenses by Project
                  Project and Description                       Jul-11       Aug-11          Sep-11      Oct-11         Nov-11        Dec-11        Jan-12        Feb-12          Mar-12      Totals
     F3PPETIMIS - MISO Transition ETI costs                      156,365      145,437         101,245      89,188         44,993       320,545        (32,977)      62,528          50,690     938,014
     F3PPRTOICE - O&M ICT Transition Costs                                                                                                                           2,556          17,957      20,512
     F3PPSPE018 - SPO VP of Strategic Initiatives                  3,379         4,412          4,039        1,827          1,297         3,654          214           (74)             79      18,826
     F3PPTDERSD - MISO Transition ALL OPCO                       471,149       297,712         84,283      481,029        (25,326)      952,680      125,444       131,111         153,804   2,671,886
     F5PPSPE044 - PMO Support Initiative-System-wide             (30,244)           (1)           (40)                                        0                                                (30,284)
     F5PPSPPCBA - ICT/RTO Cost Benefit Analysis Sty                2,572                          367                                        98                                         15       3,051
     Totals                                                      603,221       447,559        189,894      572,044        20,964      1,276,976        92,681       196,121        222,544   3,622,005


     The above costs are Entergy Texas, Inc. MISO transition expenses which have been incurred and recorded on the books for the nine months since the end of the June 30, 2011
     Test Year in in Docket No. 39896.




59
                                                                                                                                                                                                           Page 1 of 1
                                                                                                                                                                                                     Docket No. 39896
                                                                                                                                                                                                      Exhibit MPC-R-1
                                                                                                  Exhibit MPC-R-2
                                                                                                 Docket No. 39896
                                                                                                       Page 1 of 1

                                         ENTERGY TEXAS, INC.
                          ADJUSTMENT TO RITA REGULATORY COSTS IN RATE BASE
                                            TEST YEAR ENDED JUNE 30, 2011
                                                  DOCKET NO. 39896




LINE                                 DESCRIPTION                                 REF.                 AMOUNT

 1     Rita Regulatory Asset Balance in Pro Forma Rate Base (Docket 39896)   Sch P, P.19, L.23    $   26,229,627
                                                                                  AJ15.2
 2     Annual Amortization in Cost of Service                                Sch P, P.27, L.4     $    5,245,925

 3     Rita Regulatory Asset Balance in Pro Forma Rate Base (Docket 37744)        AJ15.8          $   25,278,210

 4     Amount Amortized after Dk. 37744 (Aug 15, 2010 - June 30, 2011)         10.5 Months        $    4,423,687

 5     Remaining Balance after Amortization                                  [Line 1 - Line 4]    $   21,805,940




                                                                                                            60
                                                                                  Exhibit MPC-R-3
                                                                                 Docket No. 39896
                                                                                     Page 1 of 25
                            ENTERGY TEXAS, INC.
                    PUBLIC UTILITY COMMISSION OF TEXAS
                         SOAH DOCKET NO. XXX-XX-XXXX
                    PUC DOCKET NO. 39896 - 2011 ETI Rate Case

 Response of: Entergy Texas, Inc.                 Prepared By: Steve Bridges
 to the Sixth Set of Data Requests                Sponsoring Witness: Michael P. Considine
 of Requesting Party: Cities                      Beginning Sequence No.
                                                  Ending Sequence No.

 Question No.: Cities 6-2                       Part No.:               Addendum:

 Question:

        In reference to Schedule B-1, line 7, Property Insurance Reserve, $59,799,744, please
 provide the following information:

        a. The annual Property Insurance Reserve balance by year for the period 2000
           through 2010;

        b. The amount of Hurricane Ike charges included in the Property Insurance Reserve;

        c. A copy of the Company’s current written policy explaining when costs may be
           charged to the Property Insurance Reserve;

        d. A list of all charges, showing amounts and date of charges, made to the Property
           Insurance Reserve as a result of the implementation of the Jurisdictional
           Separation Plan, along with a complete explanation as to why such charges
           should be made to the Property Insurance Reserve.


 Response:

    a. Please see the attached schedule of reserve balances and activity from June 30,
       1996 to June 30, 2011.

    b. The Hurricane Ike charges in the storm reserve as of June 30, 2011 are
       ($6,054,297).

    c. Please see the attached.


    d. Please see the attached schedule.




                                                                                           61
39896                                                                CITIES 6-2 BB272
ENTERGY TEXAS, INC.
DOCKET NO. 39896 ETI COS 6/30/11
CITIES 6TH SET QUESTION 2 (a)                                                                                         Exhibit MPC-R-3
STORM RESERVE ACTIVITY AND BALANCES FROM 6/30/96 - 6/30/11                                                           Docket No. 39896
                                                                                                                         Page 2 of 25



                                                                                 ORDERED
                      BEGINNING                                                ADJUSTMENTS                                    ENDING
      DATE             BALANCE            ACCRUALS            CHARGES             NOTE 5             OTHER         NOTE      BALANCE



     6/30/96                                                                                                                 (12,074,581)
 7/1/96-12/31/96        (12,074,581)         (1,374,246)           (421,088)                                (66)       4     (13,869,981)
      1997              (13,869,981)         (2,748,492)         13,470,336                             294,332        4      (2,853,805)
      1998               (2,853,805)         (2,748,492)          9,473,714          2,834,702          (47,499)       4       6,658,620
      1999                6,658,620          (1,650,996)          1,943,786                              10,867        4       6,962,277
      2000                6,962,277          (1,650,996)          2,525,929                                  (4)       4       7,837,205
      2001                7,837,205          (1,650,996)          3,572,550                             145,560        4       9,904,319
      2002                9,904,319          (1,650,996)          3,611,751                              17,127        4      11,882,201
      2003               11,882,201          (1,650,996)          2,224,744                                 928        4      12,456,877
      2004               12,456,877          (1,650,996)          1,914,249                                 329        4      12,720,459
      2005               12,720,459          (1,650,996)        181,422,456                                                  192,491,919
      2006              192,491,919          (1,650,996)         55,695,163                        (205,518,030)       2      41,018,056
      2007               41,018,056          (1,650,996)         24,724,965                         (11,901,675)       2      52,190,350
      2008               52,190,350          (1,650,996)        266,962,880                          12,498,325        1     330,000,559
      2009              330,000,559          (3,699,996)         96,050,815                        (362,068,336)       6      60,283,043
      2010               60,283,043          (3,699,996)           (368,762)                          3,457,091        3      59,671,376
 1/1/11-6/30/11          59,671,376          (1,849,998)          1,978,366                                                   59,799,744




NOTE 1:   Correction of state balances due to analysis during JSP split.
NOTE 2:   Adjustments to remove Storm Securitization and Insurance recoveries from the reserve.
NOTE 3:   Adjustment to Insurance recoveries recorded in 2009.
NOTE 4:   Other adjustments.
NOTE 5:   Docket 16705 ordered reserve accrual adjustment back to 6/1/96
                                             (6/1/96-12/31/98--31mos * 91,442)      2,834,702
NOTE 6: Adjustments to remove Storm Securitization and Insurance recoveries from the reserve for ($355,289,136)
        and to record the effects of the Texas Storm Securitization Settlement booked in August 2009 for ($6,779,200) for IKE.




                                                                                                                                 62
          39896                                                                                      CITIES 6-2 BB273
                                                                 Exhibit MPC-R-3
                                                                Docket No. 39896
                                                                    Page 3 of 25




                     I. POLICY SUMMARY

•   This Policy provides rules for the reporting of major storm damage
    expenditures for Entergy’s regulated Legal Entities including the
    corporate functions supporting them.

•   All employees, agents and contractors of Entergy shall immediately
    report known, suspected or potential violations of this Policy by
    following the procedures described in the Reporting Violations Policy.

•   Please refer to the following detailed Policy for further
    information.




                                                                          63
39896                                                  CITIES 6-2 BB274
                                                                                   Exhibit MPC-R-3
                                                                                  Docket No. 39896
                                                                                      Page 4 of 25




                            II. DETAILED POLICY

1.0     PURPOSE AND APPLICABILITY

        The purpose of this Policy is to establish a uniform set of rules for the reporting
        of major storm damage expenditures for the Entergy Corporation regulated Legal
        Entities (i.e., EAI, EGSL, ELL, EMI, ENOI, & ETI) with significant production,
        transmission, distribution, general plant, and/or related information technology
        (IT) facilities. This Policy will also provide the framework to ensure that storm
        project charges and storm reserve charges are accurate and that the appropriate
        internal accountabilities are established.

        This Policy applies to any and all employees of any Entergy System Company,
        unless otherwise expressly excluded, as well as agents and contractors of any
        Entergy System Company. For purposes of this paragraph, Entergy System
        Company shall mean Entergy Corporation and all of its subsidiaries and affiliates
        in which Entergy Corporation has a direct or indirect majority ownership in such
        subsidiary or affiliate.

        For employees covered by a collective bargaining agreement, the applicable
        collective bargaining agreement will govern to the extent it conflicts with this
        Policy.

        Nothing contained in this Policy should be construed to suggest that employees
        of a particular subsidiary or affiliate of Entergy Corporation are also employees of
        Entergy Corporation or any other affiliate or subsidiary of Entergy Corporation.
        Moreover, this Policy does not create any employment relationship between any
        person and any Entergy System Company.


2.0     REFERENCES & CROSS REFERENCES

                                                                                               64
39896                                                                 CITIES 6-2 BB275
                                                                                  Exhibit MPC-R-3
                                                                                 Docket No. 39896
                                                                                     Page 5 of 25




         2.1    The following policies should be read in conjunction with this Policy:

               2.1.1 Entergy Accounting Policies

                     •   Capital Funding Project Approval Policy
                     •   External Job Order Policy

               2.1.2 Entergy System Policies

                     •   Code of Entegrity
                     •   Reporting Violations

3.0     DEFINITIONS


         3.1    Incremental Costs – For EMI only, defined by the Mississippi Public
                Service Commission as, “those costs incurred for restoring
                service….that are beyond the normal costs the Company would have
                incurred absent the event.” Incremental Costs include incremental
                labor, transportation, and material costs. Normal costs would include,
                for example, compensation for normal workdays, including normal
                overtime, for those working on restoration, their transportation costs, and
                meals. Loaned Labor from other Legal Entities to EMI is considered
                incremental labor.
         3.2    Legal Entity– Refers to Entergy’s direct and indirect subsidiaries. The
                term is equivalent to PeopleSoft’s standard term “business unit” for
                accounting purposes.
         3.3    Major Storm Damage Threshold – A Storm Event with combined O&M
                and capital repair costs estimated to be $50,000 or more per occurrence
                for a particular Legal Entity, except for EMI (see Section 3.6). Also, for
                ENOI, there are additional requirements that will be reported and
                maintained by Property Accounting. (The details of these requirements
                can be obtained by request from Property Accounting.) When storm
                damage is sustained to production, distribution, transmission, general
                                                                                              65
39896                                                                 CITIES 6-2 BB276
                                                                                   Exhibit MPC-R-3
                                                                                  Docket No. 39896
                                                                                      Page 6 of 25




               plant, and/or related IT facilities, a combined cost for all functions within
               the Legal Entity affected should be used to estimate the $50,000
               threshold amount.
        3.4    Policy – this Storm Damage Policy.

        3.5    Property Insurance Account For Storm Damage – Account at each
               Legal Entity that is used to capture the approved regulatory accrual for
               storm damage expenses (also known as the Storm Damage Reserve).
               The offset for the accrual is captured in a Property Insurance expense
               account (i.e., FERC Account 924).
        3.6    Storm Damage Deductible – For EMI only, on an annual basis the
               initial $250,000 of incremental storm damage costs that will be absorbed
               by the Company. Once the annual deductible has been met, EMI
               incremental storm damage costs may be applied against the Property
               Insurance Account for Storm Damage

        3.7    Storm Damage Work Order - Term used to refer to Storm Work Orders
               and Storm Expense Work Orders collectively.

        3.8    Storm Expense Work Order – A Work Order used to accumulate all
               O&M costs for all functions other than distribution lines (e.g.
               transmission, gas, substations, IT).

        3.9    Storm Event – Hurricanes, floods, tornadoes, ice storms, high winds or
               any other act of nature that causes extensive damage to Entergy’s
               production, transmission, distribution, general plant, and/or related
               Information Technology facilities in a particular Legal Entity (i.e., EAI,
               EGSL, ELL, EMI, ENOI, & ETI).
        3.10   Capital Storm Work Order – A Work Order used to accumulate all
               costs (both O&M and Capital) for distribution lines storm damage and
               capital costs only for all other functions (e.g. transmission, gas,
               substations, IT). For Distribution Lines, Property Accounting will perform
               a monthly allocation to move O&M costs to the Property Insurance
               Account for Storm.
                                                                                               66
39896                                                                 CITIES 6-2 BB277
                                                                                  Exhibit MPC-R-3
                                                                                 Docket No. 39896
                                                                                     Page 7 of 25




         3.11   Work Order – The accounting code block element or chart field for
                projects used to accumulate costs.
         3.12   Catastrophic Event – A sudden event which causes significant
                damage to facilities in Entergy’s service territory (e.g. damage of the
                magnitude experienced by Hurricane Katrina, Hurricane Rita, and
                significant ice storms). This would include several storm project codes
                per function and typically would include more than one Legal Entity.
                This classification of an event would be implemented at the discretion of
                the Chief Accounting Officer.

         3.13   Resource Manager – Jurisdictional manager in charge of managing
                manpower and material resources for a jurisdiction.

         3.14   Material Financial Impact – Storm impacting more than 5% of
                customers and/or having a repair estimate of $5 million or more in any
                jurisdiction. Items of material financial impact do not necessarily have to
                involve specifics related to finance. For example, an initial message
                reporting outage of the number of customers could require pre-approval
                of the CAO.

         3.15   Storm Escrow Account – A dedicated “lock-box” account which is held
                in escrow for future storm events. Funds removed from this account
                may be used to reimburse Entergy for storm expenditures. The rules for
                when funds may be drawn vary by legal entity.



4.0     RESPONSIBILITIES-       Attachment     A   has    a   comprehensive     chart    of
        accountabilities.

         4.1    The Storm Incident Commander is responsible for making the decision
                to implement the storm process.


         4.2    The Chief Accounting Officer is responsible for any external filings
                necessary related to the storm, sign off on any estimates for the event

                                                                                              67
39896                                                                CITIES 6-2 BB278
                                                                                  Exhibit MPC-R-3
                                                                                 Docket No. 39896
                                                                                     Page 8 of 25




                  released externally, and sign off on any internal and external financial
                  communications that directly or indirectly include a material financial
                  impact related to storm. Other accountabilities of the CAO include:
                  determining if a storm event will be classified as a catastrophic event,
                  approving this policy and determining any exceptions to this policy.


        4.3       The Distribution Operations Area (DOA) Director and the appropriate
                  transmission, substation, general plant and IT managers are
                  responsible for coordinating and providing the initial dollar estimate of
                  the Storm Event in order to determine the need for Storm Damage Work
                  Orders. They are also responsible for all related Work Orders.


        4.4       Resource Managers are responsible for overseeing the review of
                  Distribution charges to Storm Work Orders to determine the accuracy of
                  these charges and to correct inaccurate charges.


        4.5       Transmission, Substation, and IT managers are responsible for
                  overseeing the review of their charges to their own Storm Damage Work
                  Order as well as to Distribution Storm Work Orders, and for making
                  corrections to charges, when appropriate.

        4.6       Budget Analysts are responsible for obtaining chargeable Storm
                  Damage Work Orders when the estimated dollar amount is expected to
                  meet the Major Storm Damage Threshold. They are also responsible
                  for monitoring charges to Storm Damage Work Orders and the timely
                  closing of Storm Damage Work Orders for their respective groups.


        4.7       The Property Accounting group is responsible for:


              •        issuing Storm Damage Work Orders and activating these work
                       orders for charges when notified by Budget Analysts;
              •        monitoring and reviewing the storm damage charges prior to

                                                                                              68
39896                                                                 CITIES 6-2 BB279
                                                                                   Exhibit MPC-R-3
                                                                                  Docket No. 39896
                                                                                      Page 9 of 25




                        moving the charges from the Storm Damage Work Order to the
                        Property Insurance Account for Storm Damage;
               •        reversing any non-qualifying charges to appropriate expense
                        accounts;
               •        providing reporting tools to the functional areas to assist in
                        monitoring of storm charges;
               •        providing the Tax Department with storm damage losses for use in
                        tax-return preparation and tax planning;
               •        application of the annual Storm Damage Deductible to EMI’s
                        Incremental Costs;
               •        running the monthly allocation for Distribution Lines to split costs
                        between the reserve and capital;
               •        accounting for reimbursement or recovery of storm damage
                        charges, both capital and expense.

        4.8        Jurisdictional Finance Directors are responsible for monitoring
                   reserve expense accruals to ensure accuracy, for providing internal
                   reporting of reserve balance information upon request and for providing
                   annual budget to Legal Entity cost managers.


        4.9        The Tax Department is responsible for the reporting of storm damage
                   casualty losses based on information provided by Property Accounting
                   and the DOA Directors to ensure proper recovery of tax benefits
                   associated with storm damage.


        4.10       Jurisdictional Finance Directors, in conjunction with the DOA
                   Directors, Resource Managers and Budget Analysts, are responsible
                   for training the appropriate functional area personnel in these policies
                   and procedures.      They are also responsible for forwarding and
                   coordinating estimates on an as needed basis for storm estimates
                   during a catastrophic event in conjunction with the Storm Incident
                   Commander.

                                                                                               69
39896                                                                  CITIES 6-2 BB280
                                                                                  Exhibit MPC-R-3
                                                                                 Docket No. 39896
                                                                                    Page 10 of 25




         4.11    External Reporting is responsible for recording the storm reserve
                 accruals to the Property Insurance Account for Storm Damage.

         4.12    Corporate Reporting is responsible for quarterly reporting requirements
                 relating to large Storm Events that have a material impact on quarterly
                 financial statements. They are also responsible for monitoring reserve
                 accruals and reserve balances in conjunction with Regulatory
                 Accounting, Jurisdictional Business Managers and Property
                 Accounting. For EMI only, quarterly reports summarizing the accruals
                 and charges to the Property Insurance Account for Storm Damage
                 should be furnished to Regulatory Affairs for filing with the Mississippi
                 Public Utilities Staff.

5.0     DETAILS
         5.1     Charging Guidelines for typical storm
                5.1.1 Project Codes- In the event of a storm, project codes typically will
                      be distributed by each functional business unit. When setup,
                      project codes should include the name of the storm. Property
                      Accounting will then fill out the storm name in the major storm field
                      in PowerPlant as part of the approval process. This will be the
                      basis for all storm reporting.

                5.1.2 Activity Codes- Attachment B has a listing of approved activity
                      codes to be used during a storm. This attribute will only be used
                      for internal tracking purposes.

                5.1.3 Storm Work Orders and Storm Expense Work Orders should only
                      be issued for the accumulation of cost associated with the
                      restoration of storm damage when the total cost is expected to
                      meet the Major Storm Damage Threshold. Should storm damage

                                                                                              70
39896                                                                 CITIES 6-2 BB281
                                                                      Exhibit MPC-R-3
                                                                     Docket No. 39896
                                                                        Page 11 of 25




        be incurred which will not meet the Major Storm Damage
        Threshold, the total cost should be charged against the responsible
        organization’s normal project codes (both capital and O&M, as
        appropriate). Damage costs are generally related to repair and
        replacement work associated with production, distribution,
        transmission, substations, general plant, and/or related IT facilities.


        Examples of valid storm damage charges include:
        •    All labor and material costs directly related to the restoration
             of production, distribution, transmission, general plant, and
             communication facilities, whether by replacement or repair.
        •    All food, lodging, fuel and travel expenses associated with
             the restoration effort.
        •    All Customer Service Center (CSC), Transmission
             Operations Center (TOC), Distribution Operations Center
             (DOC), and Transportation Department costs, above normal
             operating expenses, directly associated with the restoration
             effort.
        •    Communications cost associated with the restoration effort.
        •    Public safety announcements associated with the restoration
             effort.
        •    Tool, equipment, and vehicle repair costs directly attributable
             to the restoration effort.
        •    All incidental costs directly associated with the restoration
               effort.

        Examples of invalid storm damage charges include:
        •    Alcoholic beverages and tobacco products.
        •    Purchases of any tools or equipment not specifically
             required for the restoration effort that will be used beyond
             the restoration effort unless these tools were purchased to
             replace tools or equipment lost in the storm.

                                                                                  71
39896                                                    CITIES 6-2 BB282
                                                                           Exhibit MPC-R-3
                                                                          Docket No. 39896
                                                                             Page 12 of 25




              •      Purchases of personal clothing, except under extraordinary
                     circumstances.
              •      Ramp up and mobilization costs when an event does not
                     meet the major storm damage threshold amount.
              •      Facility upgrades not specifically required for the restoration
                     effort such as new carpeting on the second floor of a
                     building with flooding on the first floor only.
              •      Vegetation removal not specifically required for the
                     restoration effort unless mandated by municipal or
                     governmental authority.
              •      Replacement labor cost for any operating area that has
                     supplied construction and support personnel to the
                     restoration effort.

        5.1.4 Costs incurred for advance preparation of a Storm Event should be
              charged to the Legal Entity or entities expected to benefit from this
              advance preparation, including CSC charges. Storm Damage
              Work Orders should be credited with unused materials returned to
              the storerooms.


        5.1.5 For all legal entities, valid charges may be recorded to the Storm
              Damage Work Order in order to meet the Major Storm Damage
              Threshold (or in the case of EMI the $250,000 annual Storm
              Damage Deductible). However, for EMI, only Incremental Costs
              may be applied against the Property Insurance Account for Storm
              Damage once the deductible has been met. This includes
              incremental labor, transportation, and non-capitalized material
              costs. For EAI, non-incremental straight-time payroll and payroll
              loaders may not be applied against the Property Insurance Account
              for Storm Damage. For all other legal entities, all valid O&M
              charges may be applied against the Property Insurance Account for
              Storm Damage once the threshold has been met. If the Major

                                                                                       72
39896                                                         CITIES 6-2 BB283
                                                                                 Exhibit MPC-R-3
                                                                                Docket No. 39896
                                                                                   Page 13 of 25




                    Storm Damage Threshold is not met, valid charges to the Storm
                    Damage Work Order should be reversed and recorded against
                    normal project codes (both capital and O&M, as appropriate). For
                    EMI and EAI Distribution, budget analysts will work with Property
                    Accounting to make any non-incremental cost adjustments needed.


        5.2     Charging Guidelines for Catastrophic Event
              5.2.1 Project Codes-        In the event of a catastrophic event, all
                    communications will occur via the IE StormNet, Inside Entergy, and
                    any other communication avenue activated. When setup, project
                    codes are to include the name of the catastrophic event. Property
                    Accounting will then fill out the storm name in the major storm field
                    in PowerPlant as part of the approval process. This will be the
                    basis for all storm reporting.

              5.2.2 Activity Codes- Attachment B has a listing of approved activity
                    codes to be used during a storm. This attribute will only be used
                    for internal tracking purposes.


              5.2.3 Storm Restoration Activities – Storm Work Orders and Storm
                    Expense Work Orders should only be issued for the accumulation
                    of cost associated with the restoration of storm damage when the
                    total cost is expected to meet the Major Storm Damage Threshold.
                    Should storm damage be incurred which will not meet the Major
                    Storm Damage Threshold, the total cost should be charged against
                    the responsible organization’s normal operating budgets (both
                    capital and O&M, as appropriate). Damage costs are generally
                    related to repair and replacement work associated with Production,
                    distribution, transmission, substations, general plant, and/or related
                    IT facilities.

                    Examples of valid storm damage charges include:

                                                                                             73
39896                                                                CITIES 6-2 BB284
                                                                    Exhibit MPC-R-3
                                                                   Docket No. 39896
                                                                      Page 14 of 25




        •    All labor and material costs directly related to the restoration
             of production, distribution, transmission, general plant, and
             communication facilities, whether by replacement or repair.
        •    All food, lodging, fuel and travel expenses associated with
             the restoration effort; unless a Logistics code exists for the
             event.
        •    All Customer Service Center (CSC) costs, Transmission
             Operations Center (TOC), Distribution Operations Center
             (DOC), and Transportation Department above normal
             operating expenses, directly associated with the restoration
             effort.
        •    Communications cost associated with the restoration effort.
        •    Public safety announcements associated with the restoration
             effort.
        •    Tool, equipment, and vehicle repair costs directly attributable
             to the restoration effort.
        •    All incidental costs directly associated with the restoration
             effort.


        Examples of invalid storm damage charges include:
        •    Alcoholic beverages and tobacco products.
        •    Purchases of any tools or equipment not specifically
             required for the restoration effort that will be used beyond
             the restoration effort unless these tools were purchased to
             replace tools or equipment lost in the storm.
        •    Purchases of personal clothing, except under extraordinary
             circumstances.
        •    Ramp up and mobilization costs when an event does not
             meet the major storm damage threshold amount except
             under extraordinary circumstances approved by the Chief
             Accounting Officer.
        •    Facility upgrades not specifically required for the restoration

                                                                                74
39896                                                  CITIES 6-2 BB285
                                                                           Exhibit MPC-R-3
                                                                          Docket No. 39896
                                                                             Page 15 of 25




                     effort such as new carpeting on the second floor of a
                     building with flooding on the first floor only.
              •      Vegetation removal not specifically required for the
                     restoration effort unless mandated by municipal or
                     governmental authority.
              •      Replacement labor cost for any operating area that has
                     supplied construction and support personnel to the
                     restoration effort.

        5.2.4 Logistic Costs during a Catastrophic Event- Due to the
              complexity and high volume of costs during a Catastrophic Event,
              logistic costs will be tracked in one established project code per
              Legal Entity. Detailed records must be maintained for these costs.
              The setup of these project codes will be completed by Distribution
              and communicated via the IE StormNet.


              Examples of valid Logistics Costs include:
              • Hotel rooms for restoration crews from other Entergy Legal
                 Entities or contractors
              • Costs of tent cities
              • Costs of meals provided in bulk for restoration crews
              • Labor related to logistics coordination


              Examples of invalid Logistic Costs include:
              • Materials and supplies related to restoring service or Business
                 Continuity
              • Labor related to restoring service
              •   Costs of lodging for corporate employees working on a
                  corporate function not related to restoring service or organizing
                  logistics


        5.2.5 Non-Productive time related to storm- Employees on “release”

                                                                                      75
39896                                                            CITIES 6-2 BB286
                                                                                    Exhibit MPC-R-3
                                                                                   Docket No. 39896
                                                                                      Page 16 of 25




                      that are not able to perform any business functions due to the
                      storm must charge their time to Paid Time Off-Bad Weather. Rest
                      time for union employees should be charged to normal paid time
                      off codes.


               5.2.6 Normal Activities - Work performing normal tasks (albeit under
                     difficult or different circumstances), not related to storm restoration,
                     should be charged to typical charge codes.

               5.2.7 Business Continuity Costs during a Catastrophic Event- The
                     costs of reestablishing business operations for any function
                     relocated during a Catastrophic Event should be charged to
                     established Business Continuity Codes. Examples include planning
                     efforts by the Business Continuity Team, temporary relocation of
                     functions to provide business continuity, procurement of temporary
                     office space and lodging when mandated by employee’s supervisor
                     in conjunction with returning to work. Time specifically spent on
                     Business Continuity related tasks should be charged to established
                     Business Continuity Codes. This includes planning sessions held
                      within functions to return to business. Any approved employee
                      expenses related to redeployment should be charged to this code.
                      Charges for expenses for release employees will be the
                      responsibility of the employee and not Entergy (e.g. lodging and
                      meals). Entergy will not reimburse costs until an employee is given
                      an assignment by his or her supervisor.

         5.3    Contractor Invoice approvals and documentation during a
                Catastrophic Event- Most storm invoices will need to be approved
                through the Contractor Invoice Processing Team. Documentation must
                be received from the vendor to support costs billed.

6.0     PROCEDURES

                                                                                                76
39896                                                                  CITIES 6-2 BB287
                                                                                Exhibit MPC-R-3
                                                                               Docket No. 39896
                                                                                  Page 17 of 25




        6.1    Storm Work Orders and Storm Expense Work Orders


              6.1.1 Storm Work Order Setup – The responsible functional
                    representative determines the need for Storm Work Order or Storm
                    Expense Work Order based on the Major Storm Damage
                    Threshold definition in Section 2.0. This may involve some
                    coordination with other groups if their facilities have been impacted
                    by the same Storm Event. Budget Analysts are then required to
                    obtain an approved Storm Work Order or Storm Expense Work
                    Order. Storm Work Orders are required for damage to Distribution
                    Lines (Expense and Capital damage), and for Capital damage to
                    production facilities, substations, transmission, gas distribution,
                    general plant, and/or related IT facilities. Storm Expense Work
                    Orders are required for Expense damage to production facilities,
                    substations, transmission, gas distribution, general plant, and/or
                    related IT facilities. At a minimum, there should be one Storm
                    Work Order or Storm Expense Work Order set up for each Legal
                    Entity meeting the threshold requirements. Storm Damage Work
                    Orders must also include a Work Order (WO) estimate.

              6.1.2 Storm Preparation Costs – The responsible director and budget
                    analysts should notify Property Accounting of the need for Storm
                    Damage Work Orders for an impending Storm Event. Also, any
                    supplemental resources (e.g., labor) needed to prepare for the
                    Storm Event should be agreed upon in advance and the
                    responsible parties notified as to the appropriate Storm Damage
                    Work Order to use. The Legal Entity expected to benefit from the
                    storm preparation will be charged with these costs.


              6.1.3 Maintenance of Storm Project Codes – Budget Analysts should
                    periodically review the need for reserving additional Storm Damage

                                                                                            77
39896                                                               CITIES 6-2 BB288
                                                                               Exhibit MPC-R-3
                                                                              Docket No. 39896
                                                                                 Page 18 of 25




                    Work Orders and work with Property Accounting to set up the
                    appropriate number of Storm Damage Work Order numbers.
                    Budget Analysts may also be required to setup additional Storm
                    Damage Work Orders for approved late charges (e.g. delayed
                    contractor invoices).


        6.2    Review/Monitor Storm Damage Process

              6.2.1 Storm Charges – Budget Analysts, Resource Managers,
                    Construction & Design (C&D) Managers, Jurisdictional Finance
                    Directors, and Property Accounting should review and monitor all
                    open Storm Damage Work Orders for accuracy and
                    appropriateness from a storm project and jurisdictional perspective.


              6.2.2 Storm Damage Reserve Balances – Storm Damage Reserve
                    balances will be reviewed periodically by Property Accounting in
                    order to determine the accuracy of the reserve expense accruals
                    and the transfer of expense charges from Storm Damage Work
                    Orders. Property Accounting will provide a reserve balance
                    analysis to the Chief Accounting Officer (CAO), Vice President -
                    CFO Utility, and Regulatory Accounting on a monthly basis.
                    Property Accounting will meet quarterly with the CAO and the Vice
                    President - CFO Utility to review the most recent monthly reserve
                    balance analysis and to discuss any reserve balance issues. The
                    CAO and Vice President - CFO Utility will approve changes to
                    reserve balances.

              6.2.3 Threshold Validation – Storm Damage Work Orders should be
                    reviewed periodically by Budget Analysts and Property Accounting
                    to determine if they are in compliance with the Major Storm
                    Damage Threshold for each Legal Entity. Property Accounting will
                    make the appropriate journal entry reversals to expense should the

                                                                                           78
39896                                                              CITIES 6-2 BB289
                                                                                 Exhibit MPC-R-3
                                                                                Docket No. 39896
                                                                                   Page 19 of 25




                    Storm Damage Work Order not meet the threshold test.


              6.2.4 Monitor/Review/Close Storm Damage Work Order – Resource
                    Managers and Budget Analysts are accountable to monitor the
                    transactions being charged to the Storm Damage Work Orders and
                    review the appropriateness of all transactions and that the correct
                    project code was used. Responsible functional area management
                    is responsible for providing in-service dates for Storm Damage
                    Work Orders when storm restoration activities are completed.
                    Storm Damages Work Orders can remain in-service until all
                    charges are received, which is not expected to exceed 90 to 120
                    days after restoration activities are completed except for
                    catastrophic events, to facilitate the acceptance of late charges, but
                    should be closed as soon as feasible by entering a completion
                    date. Late charges that cause a project to be re-opened should be
                    approved by the Resource Manager and/or the appropriate
                    production, transmission, substation, general plant, IT and System
                    Crew Procurement Manager for that project, as well as the
                    Jurisdictional Finance Director for that Legal Entity.


        6.3    Billing of Storm Damage Charges

              6.3.1 Work Performed by Entergy for Others – When Entergy
                    personnel assist in storm restoration efforts outside of the Entergy
                    service territory, an External Job Order (EJO) must be set up to
                    record and ultimately bill charges to the external entity. (See
                    Entergy’s EJO Policy for more information regarding the use of
                    External Job Orders.)


              6.3.2 Work Performed by Others for Entergy – When other parties
                    (e.g., contractors, other utilities, etc.) perform storm restoration
                    work at Entergy’s request, the costs, upon billing to Entergy, should

                                                                                             79
39896                                                               CITIES 6-2 BB290
                                                                                 Exhibit MPC-R-3
                                                                                Docket No. 39896
                                                                                   Page 20 of 25




                    be charged to the Storm Damage Work Order for that Storm Event.
                    The invoice from the external party should be reviewed and
                    approved by the System Crew Procurement Manager for that
                    Storm Damage Work Order, prior to payment to the external party.
                    Any discrepancies or questions relating to the bill should be
                    reviewed and resolved with the external party prior to payment.
                    Depending on the type of storm, the payment processing will be
                    handled by the Contractor Invoice Payment Team (See paragraph
                    5.3 above.)

        6.4    Other Accounting Processes


              6.4.1 O&M/Capital Methodology – Property Accounting, in conjunction
                    with Distribution functional area personnel, is responsible for
                    determining the O&M versus Capital allocation methodology used
                    to classify the Distribution Storm Work Order charges to the
                    reserve or to Distribution capital accounts. This determination will
                    be based on retirement-unit classification and existing capitalization
                    policies. Charges from all other functions’ Storm Expense Work
                    Orders will be transferred in total to the reserve, since these Work
                    Orders should contain only O&M expense charges.

              6.4.2 Reserve Balance Adjustments – As part of the normal regulatory
                    filing process, Regulatory Accounting is responsible for requesting
                    the appropriate jurisdictional storm damage reserve accrual.
                    Regulatory Accounting shall review and obtain CAO agreement of
                    proposed storm-damage-reserve accrual amounts prior to filing
                    with jurisdictional regulatory bodies. When new amounts are
                    approved by jurisdictional regulatory bodies, Regulatory Accounting
                    is responsible for notifying Property Accounting and Corporate
                    Reporting of these and other approved adjustments to the reserve
                    balance or accrual level, after consultation with and final approval

                                                                                             80
39896                                                                CITIES 6-2 BB291
                                                                               Exhibit MPC-R-3
                                                                              Docket No. 39896
                                                                                 Page 21 of 25




                     by the CAO.


               6.4.3 Monthly Reporting Requirements –Property Accounting will
                     record the monthly storm damage accrual for each Legal Entity, as
                     well as the accumulation of charges for open Work Orders and the
                     charges to the Property Insurance Account for Storm Damage.


               6.4.4 Quarterly Reporting Requirements – Corporate Reporting is
                     responsible for the reporting of major storms that have a material
                     impact on quarterly financial statements.           This includes
                     coordinating the recording of any necessary expense or capital
                     accruals to Storm Damage Work Orders.


               6.4.5 Reimbursement and Recovery Accounting – Property
                     Accounting credits capital and the reserve account for amounts
                     received through reimbursement (CDBG, insurance) or recovery
                     (Securitization) as authorized by regulators.


               6.4.6 Storm Escrow Accounting – Property Accounting credits the
                     reserve account when funds are drawn from a Legal Entity’s storm
                     escrow account.

7.0     GUIDANCE CONTACTS


         7.1    Questions regarding the use and applicability of these policies and
                procedures should be directed to the appropriate Function Budget
                Analyst and/or the subject matter expert identified at the beginning of
                this Policy.




                                                                                          81
39896                                                              CITIES 6-2 BB292
                                                                                     Exhibit MPC-R-3
                                                                                    Docket No. 39896
                                                                                       Page 22 of 25




           8.0   ATTACHMENTS
                 Attachment A : Summary of Accountabilities and Responsibilities


Activity                                                                 Person and/or Group
                                                                         Responsible
Responsible for making the decision to implement the storm process for Storm Incident Commander
system event
Responsible for any external filings necessary related to the storm CAO
including a Form 8-K
Approval of any estimates for the event released externally              CAO
Approval of any communications related to storm including those made CAO
by Regulatory and Investor Relations
Release pre-approved project codes in advance of a storm                 Functional Budget
                                                                         Coordinators
Approve project codes in advance of a storm                              Property Accounting
Responsible for ensuring coding of storms for ENOI with alerts from Property Accounting
National Weather Service
Classification of storm as storm event, catastrophic event, or an event CAO and/or Property
that doesn’t meet threshold for storm accounting                        Accounting Manager
Provide estimate to ensure that the threshold has been reached for Storm Distribution Operations Area
Event to appropriate JFD’s and VP CFO of Domestic Utility. This effort (DOA) Director and the
will be coordinated by CAO or Property Accounting Manager.               appropriate transmission,
                                                                         substation, general plant
                                                                         and IT managers (For a
                                                                         systemwide event, this
                                                                         responsibility would be
                                                                         completed partially by the
                                                                         System Command Center.)
Determine that a project code(s) is needed for an event and setup and Functional Budget
approve project codes needed on an emergency basis as needed          Coordinators and Property
                                                                         Accounting Manager
Providing pertinent information to CAO and VP CFO of Domestic Utility    JFD’s
                                                                                             82
       39896                                                             CITIES 6-2 BB293
                                                                                     Exhibit MPC-R-3
                                                                                    Docket No. 39896
                                                                                       Page 23 of 25




Activity                                                                 Person and/or Group
                                                                         Responsible
Ensure that information is funneled into the Present Estimate Process    CAO, JFD’s, and Business
                                                                         Unit CFO’s
Communicate project codes for a typical storm within functional area     Functional Budget
                                                                         Coordinators and Outage
                                                                         Management
Communicate project codes for a catastrophic event via IE StormNet and Property Accounting
Inside Entergy                                                         Manager and Corporate
                                                                         Communications
Code transactions/ source documents with proper coding for storm events Transaction originator or
(i.e. timesheets, invoices, and PassPort transactions)                  assigned accountable
                                                                         employee
Ensure that proper documentation obtained for storm transactions for Transaction originator or
processing                                                           assigned accountable
                                                                         employee
Reviewing and approving contractor storm invoices in a catastrophic Contractor Invoice
event or in any storm event that the team is deemed necessary including Processing Team
documentation
Review and approve the coding of other transactions/source documents Supervisor of employee
as proper for storm events (i.e. timesheets, invoices, and PassPort recording transaction
transactions) that are routed to Supervisor for approval
Review storm transactions to ensure the proper coding at a summary Functional Budget
level                                                                    Coordinators
Work with operational teams to process any necessary corrections         Functional Budget
                                                                         Coordinators
Monitoring of charges to Project Codes                                   Business Unit CFO’s,
                                                                         Jurisdictional Finance
                                                                         Directors, Functional
                                                                         Budget Coordinators, and
                                                                         Property Accounting
                                                                         Manager
                                                                                             83
        39896                                                            CITIES 6-2 BB294
                                                                                     Exhibit MPC-R-3
                                                                                    Docket No. 39896
                                                                                       Page 24 of 25




Activity                                                                 Person and/or Group
                                                                         Responsible
Monitoring and reviewing the storm damage charges prior to moving the Property Accounting
charges from the Storm Damage Work Order to the Property Insurance
Account for Storm Damage
Application of the annual Storm Damage Deductible to EMI’s Incremental Property Accounting
Costs


Recording the storm reserve accruals to the Property Insurance Account External Reporting
for Storm Damage
Reconciling Storm Damage related accounts                                Property Accounting
Responsible for monitoring reserve expense accruals to ensure accuracy, Jurisdictional Finance
for providing internal reporting of reserve balance information upon Directors
request and for providing annual budget to Legal Entity cost managers.
Responsible for approving the policy and determining any exceptions to CAO
the policy
Responsible for training the appropriate functional area personnel in JFD’s, DOA Directors,
these policies and procedures                                         Resource Managers,
                                                                      Property Accounting, and
                                                                         Budget Analysts
Providing reports for catastrophic events                                Cost Reporting and
                                                                         Analysis (Diane Bryars and
                                                                         Bert Fisher)
Answering questions on the proper coding of transactions or transaction Functional Budget
processing                                                              Coordinators with
                                                                        assistance from Property
                                                                         Accounting Manager




                                                                                             84
       39896                                                             CITIES 6-2 BB295
                    ENTERGY TEXAS, INC.
                    DOCKET NO. 39896 ETI COS 6/30/11
                    CITIES 6TH SET QUESTION 2 (d)
                    JSP STORM RESERVE CORRECTIONS BY PROJECT


                                                                              ETI JSP STORM
                                                                                RESERVE          ORIGIONAL        ORIGIONAL
                                                                              ADJUSTMENT        EGSL AMOUNT      ETI AMOUNT
                        Project                    Project name                    1/1/08         @12/31/07       @12/31/07      TOTAL                            REASON




39896
                    C7PCSJ8001    STORM DAMAGE DL EGSI SW TX 10/24/97                52,507           52,507          75,482       127,989    Move charges on TX project from LA.
                    C7PCSJ8009    STORM DAMAGE DL SOUTHWEST FRAN 11/2                57,692           57,692          86,637       144,329    Move charges on TX project from LA.
                    C7PCSJ8010    STORM DAMAGE DL SOUTHWEST FRAN 12/3                93,831           93,831          12,358       106,189    Move charges on TX project from LA.
                    C7PCSJ8011    STORM DAMAGE DL SOUTHWEST FRAN 12/3                39,537           39,537         (13,381)       26,156    Move charges on TX project from LA.
                    C7PCSJ8013    STORM DAMAGE DL SOUTHWEST FRAN 12/8                64,190           64,190          19,955        84,145    Move charges on TX project from LA.
                    C7PCSJ8014    STORM DAMAGE DL SOUTHWEST FRAN 1/6/                86,584           86,584         112,061       198,645    Move charges on TX project from LA.
                    C7PCSJ8017    STORM DAMAGE DL SOUTHWEST FRAN 1/21               204,369          204,369         114,571       318,940    Move charges on TX project from LA.
                    C7PCSJ8021    STORM DAMAGE DL SOUTHWEST FRAN 2/10                25,090           25,090           1,520        26,610    Move charges on TX project from LA.
                    C7PCSJ8025    STORM DAMAGE DL SOUTHWEST FRAN 2/26               362,039          362,039             (37)      362,002    Move charges on TX project from LA.
                    C7PCSJ8030    STORM DAMAGE DL SOUTHWEST FRAN 3/16                23,718           23,718         (10,162)       13,556    Move charges on TX project from LA.
                    C7PCSJ8041    STORM DAMAGE DL SOUTHWEST FRAN 6/5/                49,088           49,088         (12,677)       36,412    Move charges on TX project from LA.
                    C7PCSJ8101    STORM DL SOUTH FRAN EGSI 5-10-99                  (53,386)         129,632          53,386       183,018    Move charges on LA project from TX.
                                                                                                                                              Move charges on project from LA because
                    C7PCT91743    STORM DAMAGE DL SOUTH FRAN EGSI 7/7                 27,593           27,593             -          27,593   owner dept is a TX department.
                    C7PPSJ8262    Storm Dmg Dist Texas EGSI 5/11/04                   92,571           92,571         312,452       405,023   Move charges on TX project from LA.
                    C7PPSJ8263    Storm Dmg Dist Texas EGSI 6/4/04                    19,662           19,662          45,247        64,909   Move charges on TX project from LA.
                    C8PPKATRNA    Katrina Storm Accrual Project                    1,307,046        1,611,980      (1,307,046)      304,934   To zero out TX credit balance
                    E2PCSJ8012    STORM DAMAGE TL S/WEST 12/7/97                      26,244           26,244           8,253        34,497   Move charges on TX project from LA.
                    E2PCSJ8085    GSU-LA SOUTH GRID TL STORM DAMAGE 1                (86,485)         (27,352)         86,485        59,133   Move charges on LA project from TX.
                    E2PCSJ8228    HURRICANE LILI-EGSI-LA GRID 9/30/02                (94,565)      11,252,175          94,565    11,346,740   Move charges on LA project from TX.
                                                                                                                                              Move charges on project from LA because
                    E2PCT90530    GSU STORM DAMAGE 1/13/95                            36,675           36,675             -         36,675    owner dept is a TX department.
                                                                                                                                              Move charges on project from LA because
                    E2PCT90542    STORM DAMAGE SUBSTATION                             28,521           28,521             -          28,521   owner dept is a TX department.
                    E2PCT91726    STORM DAMAGE DL EGSI SOUTHWEST TX               (2,380,424)      (2,380,424)     14,587,931    12,207,506   Move credit charges on TX project from LA.
                    E2PPCPSJOM    Katrina Storm O&M for Corp Support               1,694,626        3,034,588       2,467,733     5,502,321   Split based on Billing Method of project.
                    E2PPN09192    HURRICANE KATRINA (RBS) - 2005                     (67,749)          74,132          67,749       141,881   Move charges on LA project from TX.
                    E2PPSJ8274    Trans. Storm EGSI-LA 5/29/05                       (12,739)          20,425          12,739        33,164   Move charges on LA project from TX.
                    E2PPSJ8279    Trans. Storm EGSI-TX on 1/13/2005                   20,508           20,508          17,492        38,001   Move charges on TX project from LA.
                    E2PPSJ8284    EGSI-TX Storm on 6/15/2005-Trans                    67,325           67,325          57,291       124,616   Move charges on TX project from LA.
                    E2PPSJ8291    Trans EGSI-TX Hurrican Rita 9-24-05             10,652,130       10,652,130      (4,859,002)    5,793,128   Move charges on TX project from LA.
                    E2PPSJ8296    Trans. Hurricane Katrina - EGSI-La                (461,934)         629,996         461,934     1,091,930   Move charges on LA project from TX.
                    E2PPSJ8302    Trans EGSI-LA Hurrican Rita 9-24-05             (1,407,114)       1,957,840       1,407,114     3,364,954   Move charges on LA project from TX.
                    E2PPSJ8313    Trans. Storm EGSI-LA 10/19/2006                    (16,134)          18,333          16,134        34,467   Move charges on LA project from TX.
                    E2PPSJ8354    Trans Hurr Humberto EGSI-TX 9/12/07                744,037          744,037         681,062     1,425,099   Move charges on TX project from LA.
                    E2PPSJITG1    IT O&M STORM Rita                                  225,704          225,704        (158,912)       66,792   Move credit charges on LA project from TX.
                    E2PPWJ0055    EGSI Storm Damage and Prep 2004                    (10,276)          11,450          10,276        21,726   Move charges on LA project from TX.
                    E2PPWJ0065    EGSI Storm Prep &damage '05 Katrina                (25,223)          27,050          25,223        52,273   Move charges on LA project from TX.
                    E2PPWJ0080    Humberto Restoration - TX                          129,694          129,694         119,385       249,079   Move charges on TX project from LA.
                    F3PPN09179    RBS FO 06-03 FEEDWATER VALVES(1006)                 23,644           23,644         (23,644)          -     Move credit charges on LA project from TX.
                    F5PCZZI06P    CASUALTY AND SURITY BONDS                          (73,849)         (73,849)         73,849           -     Move charges to zero out project.

                                                                                                                                           Project split based on analysis of detail charges.
                    F5PPCDBGWO Hurricane Project for CDBG Funds                     276,465          223,433         119,946       343,379 At 12/31/07 all securization proceeds were LA.

                                                                                                                                           Project split based on analysis of detail charges.
                    F5PPRTARPT    Storm Cost Processing & Review Rita               721,931          521,129         194,013       715,142 At 12/31/07 all securization proceeds were LA.




CITIES 6-2 BB296
                    VARIOUS PROJECTS                                                  35,183                                                  Project split based on analysis of detail charges.




               85
                                                     TOTAL TEXAS CORRECTION       12,498,325       30,183,491      14,957,984    45,141,474
                                                                                                                                                                                                      Page 25 of 25
                                                                                                                                                                                                   Docket No. 39896
                                                                                                                                                                                                    Exhibit MPC-R-3
                                                                           Exhibit MPC-R-4
                                                                          Docket No. 39896
                                                                                Page 1 of 8




Date:        February 27, 1995

To:          Distribution List

From:        Donald R. Willis

Subject:     Storm Damage Accounting Procedures

Attached is the current Entergy Storm Damage Accounting procedures. The
procedures will be incorporated in the Systemwide Emergency Response Plan
soon. We are sending the procedures through cc:Mail to insure that the people
directly involved in the storm damage process receive a copy.

Should you have any questions, please refer to the contacts listed on Page 6.

DRW/jlw
Attachments
cc:         Lee Randall




                                                                                        86
                                                                            Exhibit MPC-R-4
                                                                           Docket No. 39896
                                                                                 Page 2 of 8




                    Storm Damage Accounting Procedures
                             Distribution List




Delbert Zimmerly    John Scott             James Milton        Bennie Daigle
Gary Lamkin         Mike Simoneaux         Bill Compton        Ron Rowland
Larry Fincher       Vincent Frisella       Donna Childers      Charles Davis
Don Newell          Gordon Miano           Brent Forte         Ronnie Teague
AI Grille           Oscar A. Meyer         Debra Dodson        Jim Wilbanks
Harry Keller        Gary Bazile            Carol Brady         Clyde Reeves
Randy Helmick       Sammy Rawls            Mark Russo          Phillip Moore
David Sermons       Orville Bratschi       Edwin Berger
John Sherrod        Duane Sistrunk         Daniel Pruhomme
Danny Taylor        Tommy Castleberry      Belinda Welch
John Zemanek        Peter Nienaber         Marcia Ross
Don Schaeffer       Dewey Evans            Michael J. Murray
Charlotte Tisdale   Paul Leist
Adrian Greene       Lester Lewis
Dianne Cochran      Robert Glach
Alan Oswalt         Randy Hebert
James Dixon         Alfred (Joe) Gertsch
Sarah Davis
David Stevens


cc:

Lee W. Randall      Janie Tucker           Sandra Wilson       Bobbie Jackson
Steve Pisciotta     Karen Collins          Phil Gillam         Gerri Ringgold
Mark Madere         Margaret Heuston       Karen Allen         Sue Merritt
Brian Burns         John Hollingshead      Dowell Harlan
                    Sharon Reed




                                                                                         87
                                                                               Exhibit MPC-R-4
                                                                              Docket No. 39896
                                                                                    Page 3 of 8




 I. PURPOSE

    To establish a uniform procedure for (1) the reporting of major storm damage
    maintenance repair expenses and (2) the reporting of plant replacement costs
    associated with major storm damages to plant facilities.

    Storm Damage casualty losses are reported for income tax purposes. The
    accounting procedures set forth in this document are necessary for accurate
    reporting of these costs.

II. RESPONSIBILITY

    Property Accounting Managers, Distribution and Transmission Lines and
    Substations

Ill. · DEFINITIONS

    Major Storm Damage- A storm with O&M repair costs estimated to be $50,000
    or more per legal entity for AP&L, GSU, LP&L, and NOPSI. Major storm
    damage for MP&L shall be defined as a storm with total costs (O&M and
    Capital) of $50,000 or more. When storm damage is sustained to both
    distribution and transmission facilities, a combined cost for all functions should
    be used to estimate the $50,000 limit.

    Minor Storm Da111age - A stotrrt witlt O&M tepait costs estimated to be less
    than $50,000 per legal entity for AP&L, GSU, LP&L, and NOPSI. Minor storm
    damage for MP&L shall be defined as a storm with total costs (O&M and
    Capital) less than $50,000.

IV. MAJOR STORM DAMAGE - DISTRIBUTION LINES

    For Major Distribution Lines storm damage, region personnel shall request
    from Property Accounting a Job Order number for each storm for the
    applicable legal entity. Property Accounting will issue one job order number
  · per legal entity and region that will be used to accumulate all costs, Capital
    and O&M. Therefore, when storm damage is sustained by two regions within
    the same legal entity, one job order number will be issued for each region
    affected. In the case of GSU and the Southwest Region, one job order
    number will be issued for each state.




                                    Page 1 of 6


                                                                                            88
                                                                            Exhibit MPC-R-4
                                                                           Docket No. 39896
                                                                                 Page 4 of 8




IV. MAJOR STORM DAMAGE- DISTRIBUTION LINES (continued)

    Authority for Distribution Line Facilities:
    The E&O Director shall be responsible for authorizing the request of a stonn
    damage job order by Region personnel. Within seven days of issuance of a
    storm damage job order, the E&O Director shall provide written notification to
    the Property Accounting Manager, Distribution Lines specifying the date of the
    stonn, type of storm, and locations involved. This written notification must
  · include an estimate of the total cost of the stonn detailed by Capital and O&M
    as well as the overall Capital and O&M percentages.

   When storm damage is sustained to two regions within the same legal entity,
   the E&O Directors for both regions shall be responsible for coordinating to
   determine if the combined repair cost meets the $50,000 limit and warrants
   issuance of a storm damage job order. The paperwork and information
   referenced above shall be required from all regions affected.

   All charges to storm damage job orders should be coded to Account 174. 1 and
   the appropn·ate responsible location.

    Job Order Review and Cost Allocation:
    Property Accounting will review storm damage job orders for Capital & O&M
    costs. The capital costs associated with a major storm will be transferred to a
    Capital Expe11ditme Aulliorization (CEA) on the appropnate responsibilitY
    budgets for all Operating Companies. Capital costs less than $50,000 will be
    transferred to a blanket CEA. Property Accounting will request a Long Form
    CEA from the E&O Director if capital costs for an individual storm exceed
  · $50,000. The Long Form CEA for major storm damage should be routed for
    approvals according to SBU guidelines and returned to Property Accounting
    within 60 days of the storm's occurrence.

   The O&M costs associated with a major storm will be transferred to the
   Property Insurance Reserve for AP&L, GSU, LP&L, and NOPSI. The MP&L
   Eastern Region Support department shall review the O&M costs on a major
   storm for MP&L to determine incremental costs. The incremental costs will be
   transferred to the Property Insurance Reserve. Non-incremental costs will be
   charged to normal O&M accounts on the appropriate responsibility budgets.




                                   Page 2 of6


                                                                                         89
                                                                             Exhibit MPC-R-4
                                                                            Docket No. 39896
                                                                                  Page 5 of 8




IV. MAJOR STORM DAMAGE- DISTRIBUTION LINES (continued)

  · Retirements Processing:
    Retirements associated with a major storm will be handled on a one-for-one
    basis for Distribution Lines. Property Accounting will record one retirement for
    each unit of property installed on a storm. The E&O Director shall notify
    Property Accounting if significant re-routes or other complications occurred
    during the storm restoration to make this methodology unreasonable.

   Completion Reporting:
   Upon completion of storm damage restoration work, the Property Accounting
   Manager, Distribution Lines shall be given written notification of the date of
   completion of the repairs. Storm damage job orders shall be closed to source
   system charges 60 days after the completion date provided to Property
   Accounting. All Service Requests (discussed in Section VI) and Intercompany
   Job Orders (discussed in Section X) that were established in direct support of
   a storm shall also be closed at that time.

V. MAJOR STORM DAMAGE- SUBSTATIONS & TRANSMISSION LINES

  . For major storm damage to Substations and Transmission Lines, field
    personnel should request from Property Accounting a Job Order number to
    accumulate O&M costs and a CEA number to accumulate capital costs for
    eacli storm. An emergency CEA number shall be 1ssued by Property
    Accounting for each Transmission Line and for each Substation property
    section with estimated capital costs exceeding $50,000. Field personnel must
    submit a completed Long Form CEA to Property Accounting within 60 days of
    the storm's occurrence. The Long Form CEA for major storm damage should
    be routed for approvals according to SBU guidelines. The Short Form CEA
    should be used if the capital charges are less than $50,000.

   Job Order Review and Cost Allocation:
   The O&M costs associated with a major storm will be transferred to the
   Property Insurance Reserve for AP&L, GSU, LP&L, and NOPSI. The MP&L
   Eastern Region Support department shall review the O&M costs on a major
   storm for MP&L to determine incremental costs. The incremental costs will be
   transferred to the Property Insurance Reserve. Non-incremental costs will be
   charged to normal O&M accounts on the appropriate Responsibility budgets.

   Retirements Processing:
   Units of property destroyed by a major storm for Substations and Transmission
   Lines must be specifically identified and retired.


                                   Page 3 of6


                                                                                          90
                                                                                Exhibit MPC-R-4
                                                                               Docket No. 39896
                                                                                     Page 6 of 8




  V.   MAJOR STORM DAMAGE - SUBSTATIONS & TRANSMISSION LINES
       {continued)

       Completion Reporting:
       Upon completion of storm damage O&M repair work, the Property Accounting
       Managers, Transmission Lines and Substations shall be given written
       notification of the date of completion of the repairs. Storm damage job orders
       shall be closed to source system charges 60 days after the completion date
       provided to Property Accounting. All Service Requests (discussed in Section
       VI) and Intercompany Job Orders (discussed in Section VI) that were
       established in direct support of a storm shall also be closed at that time. Page
       3 of the CEA Long form shall be used to report completion of capital work
       associated with major storm damage to Substations and Transmission Lines.

VI.. ESI EXPENDITURES

       When ESI employees provide assistance in storm damage restoration work, a
       Service Request (SR) should be requested from Property Accounting. The SR
       shall be used to accumulate ESI payroll and other employee expenses and to
       bill these costs to the appropriate Operating Company. Property Accounting
       should be informed of the ESI locations providing the assistance and the
       Operating Company locations and functions that will receive the benefit of
       these services.

VII.   SCOPE OF STORM DAMAGE CHARGES

       The use of Storm Damage Job Orders is confined to repair work associated
       with distribution and transmission lines and substations. These job orders
       should primarily be used to accumulate costs directly associated with the
       repair of these systems. Examples of valid storm damage charges include, but
       are not limited to, the following:

       - Installing and removing units of property for Distribution Lines
       - Clearing Hnes of brush and debris
       - Splicing, retying, and resagging of existing conductors
       - Straightening and transferring existing facilities
       - Replacing fuses
       - Repairing transmission towers not constituting replacement of a unit of
         property
       - Repairing tower foundations




                                      Page 4 of6


                                                                                             91
                                                                                 Exhibit MPC-R-4
                                                                                Docket No. 39896
                                                                                      Page 7 of 8




 VII.    SCOPE OF STORM DAMAGE CHARGES (continued)

          Storm damage job orders should also be used to accumulate costs incurred by
          Company personnel in direct support of storm restoration efforts. Business
          Office clerical personnel when working on storm related procedures, such as
          answering the telephone, posting payroll, etc., should charge their time to
          storm damage job orders. Any General Office personnel who provide support
          in storm damage activity should charge their time and other expense to storm
        · damage job orders.

         Field personnel should contact the applicable Property Accounting Manager
         should additional clarification on the appropriateness of storm damage charges
         be required.

VIII.    GENERAL OFFICE EQUIPMENT

         A specific CEA should be obtained from Property Accounting for any General
         Plant type property, such as fax machines and radio equipment, etc.,
         purchased during a major storm that should be capitalized under the General
         Plant Capitalization Criteria. The purchaser of such equipment shall be
         responsible for requesting a CEA. An emergency CEA number can be issued
         by Property Accounting if time does not permit the preparation of detailed
         paperwork and definitive estimates. A completed CEA Form routed for
         app10vals accotding to SBU guidelines should be submmed to Property
         Accounting within 30 days after the issuance of the emergency CEA number.

  IX. MINOR STORM DAMAGE -ALL FUNCTIONS

         For Minor storm damage, maintenance expenses should be handled through
         the normal process. For capital costs associated with a minor storm, the Short
         Form CEA may be used for each Transmission Line and Substation Property
         Section. The Distribution Lines Improvement Blanket CEA shall be used for
         capital costs associated with a minor storm affecting Mass Distribution.

  X. ASSISTANCE TO OTHER ENTERGY COMPANIES

         For work performed for a different legal entity, a separate job order should be
         requested from Property Accounting to facilitate the intercompany billing
         process.




                                        Page 5 of 6


                                                                                              92
                                                                        Exhibit MPC-R-4
                                                                       Docket No. 39896
                                                                             Page 8 of 8




XI. CONTACTS

  · Please contact the following Property Accounting personnel for storm damage
    related assistance:

   Distribution Lines:
   Don Willis                Manager                   501-377-5788
   Sandra Wilson             AP&L, GSU, LP&L,          50.1-377-5679
                             NOPSI, MP&L

   Transmission Lines:
   Phil Gillam               Manager                   501-377-5785
   Karen Allen               MP&L, LP&L, NOPSI         501-377-5787
   Dowell Harlan             AP&L, GSU                 501-377-5675

   Substations:
   Janie Tucker              Manager                   501-377-5721
   Karen Collins             GSU                       501-377-5685
   Margaret Heuston          AP&L                      501-377-5717
   John Hollingshead         MP&L, NOPSI               501-377-'5713
   Sharon Reed               LP&L                      501-377-5703

   General Plant:
   Janie Tucke1              Mar1ager                  501-377-5721
   Bobbie Jackson            AP&L, LP&L, NOPSI         501-377-5662
   Gerri Ringgold            GSU,MP&L                  501-377-5671




                                                                         2-24-95




                                 Page 6 of6


                                                                                     93
                                                                               Exhibit MPC-R-5
                                                                              Docket No. 39896
ENTERGY TEXAS INC                                                                   Page 1 of 1
DOCKET NO. 39896
TYE: 6/30/2011


ETI PAYROLL ADJUSTMENT

Test Year End Headcount Proformed to by ETI         WP/P AJ 22.13            675
February 2012 Headcount                             Staff 13-16              660
                  Decrease                                                   (15)


Annual Salary                       WP/P AJ 22.13                   $     78,575
                    Payroll Decrease                                $ (1,178,625)


O&M Percentage                      WP/P AJ 22.13                         55.01%
                    Total O&M Decrease                              $   (648,362)


Other Payroll Related Expenses

Benefits                   38.95%   WP/P AJ 22.13                       (252,537)

FICA                        7.65%   WP/P AJ 22.13                        (49,600)

FUTA                        0.08%   WP/P AJ 22.13                           (519)

SUTA                        1.03%   WP/P AJ 22.13                         (6,678)

                    Total Payroll Related Increase                  $   (309,333)


Total ETI Labor Decrease                                            $   (957,695)

Total Staff ETI Payroll Adjustment (Exhibit AG-7)                   $ (1,181,912)

Change to Staff's Adjustment                                        $   224,217




                                                                                            94
                                                                                       Exhibit MPC-R-6
                                                                                      Docket No. 39896
ENTERGY TEXAS INC                                                                           Page 1 of 1
DOCKET NO. 39896
TYE: 6/30/2011


ESI PAYROLL ADJUSTMENT


Test Year End Headcount part time                   EXHIBIT MPC-R-7               74
December 2011 Headcount part time                   Staff 7-4                     48
                Decrease in part time                                           (26)

Factor to convert part time to full time equivalentEXHIBIT MPC-R-7             41%
                  Full Time Equivalent Decrease                              (10.66)

Test Year End Headcount full time                   WP/P AJ 22.24              3054
December 2011 Headcount full time                   Staff 7-4                  3089
                Increase in full time                                           35

Increase in Full time                                                            35
Less: Part time as Full time equivalent                                      (10.66)
                   Net Full time equivalent change                            24.34

Annual Salary                    WP/P AJ 22.24                        $      97,580
                   Payroll Increase                                   $   2,375,097

Percentage to ETI            WP/P AJ 22.24                                   9.33%
                Payroll Increase to ETI                               $    221,597


O&M Percentage                   WP/P AJ 22.24                              81.02%
                   Total O&M Increase                                 $    179,538


Other Payroll Related Expenses

Benefits                46.33% WP/P AJ 22.24                                83,180

FICA                      7.65% WP/P AJ 22.24                               13,735

FUTA                      0.08% WP/P AJ 22.24                                  144

SUTA                      1.03% WP/P AJ 22.24                                1,849

                   Total Payroll Related Increase                     $     98,907


Total ETI Labor Increase from ESI                                     $    278,445

Total Staff ESI Payroll Adjustment (Exhibit AG-7)                     $    240,914

Change to Staff's Adjustment                                          $     37,531




                                                                                                    95
                                                                    Exhibit MPC-R-7
                                                                   Docket No. 39896
                                                                         Page 1 of 1

ENTERGY TEXAS INC
DOCKET NO. 39896
TYE: 6/30/2011


FACTOR TO CONVERT PART TIME TO FULL TIME EQUIVALENTS



                       Part-Time Temporary           Total Part
                       Employees Employees             Time
                         Cities 12-6   Cities 12-7
              Jul-10          35        41                    76
            Aug-10            36        26                    62
            Sep-10            36        23                    59
             Oct-10           35        25                    60
            Nov-10            35        25                    60
            Dec-10            35        21                    56
             Jan-11           37        21                    58
            Feb-11            36        22                    58
            Mar-11            34        21                    55
             Apr-11           35        20                    55
            May-11            35        33                    68
             Jun-11           35        39                    74
     Test Year Average Part Time Employees                 61.75

         Test Year Part Time Pay Cities 12-6          1,355,752
        Test Year Temporary Pay Cities 12-7           1,121,683
                                                      2,477,435

          Average Part Time Pay                          40,120
          Full Time Annual Salary WP/P AJ 22.24          97,580
  Part Time % of Full Time Salary                           41%




                                                                                 96
                                                                                               Exhibit MPC-R-8
                                                                                              Docket No. 39896
                                                                                                    Page 1 of 1
ENTERGY TEXAS INC
DOCKET NO. 39896
TYE: 6/30/2011

                  ETI Direct Costs of Incentive Compensation Adjustment based on Financial Goals


                                                               ETI            STAFF                STAFF
                                                             REQUEST       ADJUSTMENT           RECOMMENDED

Non-Executive Compensation Plans

Management Incentive Plan                  Staff 10-1    $     1,184,198   $      (166,972)     $      1,017,226
Exempt Incentive Plan                      Staff 10-1    $       983,868   $      (138,725)     $        845,143
Teamshare Incentive Plan                   Staff 10-1    $        71,465   $       (10,077)     $         61,388
Teamshare Bargaining Incentive Plan        Staff 10-1    $       384,883   $       (54,269)     $        330,614
              Total                                      $     2,624,414   $      (370,042)     $      2,254,372

Payroll Taxes at 7.65%                                                     $       (28,308)


Executive Compensation Plans

Executive Annual Incentive Plan            Staff 10-1    $       185,414   $       (26,143)     $        159,271
Restricted Share                           Staff 10-1    $             -   $             -      $              -
Restricted Stock Incentive                 Staff 10-1    $        20,993   $       (20,993)     $              -
Long-Term Incentive Plan                   Staff 10-1    $        16,652   $       (16,652)     $              -
Equity Awards                              Cities 10-9   $       193,187   $      (193,187)     $              -
              Total                                      $     5,665,074   $      (256,975)     $      4,668,014

Payroll Taxes at 1.45% (Medicare Portion Only)                             $        (3,726)

Total Payroll Taxes                                                        $       (32,034)

Staff Payroll Taxes at 7.65% (All Plans)                                   $       (47,967)

Change to Staff's Adjustment                                                       15,933




                                                                                                            97
                                                                                              Exhibit MPC-R-9
                                                                                             Docket No. 39896
                                                                                                   Page 1 of 1
ENTERGY TEXAS INC
DOCKET NO. 39896
TYE: 6/30/2011

                ESI Allocated Costs of Incentive Compensation Adjustment based on Financial Goals


                                                               ETI            STAFF               STAFF
                                                             REQUEST       ADJUSTMENT          RECOMMENDED

Non-Executive Compensation Plans

Management Incentive Plan                  Staff 10-1    $     3,564,996   $     (502,664)      $      3,062,332
Exempt Incentive Plan                      Staff 10-1    $       874,472   $     (123,301)      $        751,171
Teamshare Incentive Plan                   Staff 10-1    $        81,983   $      (11,560)      $         70,423
              Total                                      $     4,521,451   $     (637,525)      $      3,883,926

Payroll Taxes at 7.65%                                                     $      (48,771)


Executive Compensation Plans

Executive Annual Incentive Plan            Staff 10-1    $     1,298,037   $     (183,023)      $      1,115,014
Restricted Stock Incentive                 Staff 10-1    $       135,242   $     (135,242)      $              -
Long-Term Incentive Plan                   Staff 10-1    $       213,003   $     (213,003)      $              -
Restricted Share                           Staff 10-1    $       346,256   $     (346,256)      $              -
Equity Awards                              Cities 10-9   $     3,467,026   $   (3,467,026)      $              -
              Total                                      $     5,459,564   $   (4,344,550)      $      1,115,014

Payroll Taxes at 1.45% (Medicare Portion Only)                             $      (62,996)

Total Payroll Taxes                                                        $     (111,767)

Staff Payroll Taxes at 7.65% (All Plans)                                   $     (381,129)

Change to Staff's Adjustment                                                      269,362




                                                                                                           98
                                                                                                                        Exhibit MPC-R-10
                                                                                                                        Docket No. 39896
                                                                                                                               Page 1 of 1

Entergy Electric System                           Date range - 20120201 through 20120229                                         Attachment 6-ETI
Intra-System Billing-201202RA                     Company Summary - Entergy Texas, Inc                                                   Page 48



                                                                     Sales(KWH)         Purchases(KWH)     Revenue($)              Expense($)

Purchases and Sales - Associated Companies

Exchange Energy                                                           21,585,809         88,305,013         915,278.42               2,627,526.97
AECC Excess Energy                                                                 0          7,687,494               0.00                 209,869.14
ARK.NU 1 - UPP from AR Desig. Energy                                               0         15,933,310               0.00                       0.00
ARK.NU 2 - UPP from AR Desig. Energy                                               0         18,830,541               0.00                       0.00
CALCASIEU 1 - UPP from EGSL Desig. Energy                                          0          7,651,700               0.00                       0.00
CALCASIEU 2 - UPP from EGSL Desig. Energy                                          0          6,691,200               0.00                       0.00
GGULF RET - UPP from AR Desig. Energy                                              0          7,107,427               0.00                       0.00
GGULF RP - UPP from AR Desig. Energy                                               0          3,595,189               0.00                       0.00
INDEPN 1 - UPP from AR Desig. Energy                                               0          4,157,524               0.00                       0.00
NELSON 4 - UPP from EGSL Desig. Energy                                             0         57,569,650               0.00                       0.00
PERVIL 1 - UPP from EGSL Desig. Energy                                             0         42,371,487               0.00                       0.00
RVRBND 1 - UPP from EGSL Desig. Energy                                             0        204,378,222               0.00                       0.00
WH.BLF 1 - UPP from AR Desig. Energy                                               0          7,177,453               0.00                       0.00
WH.BLF 2 - UPP from AR Desig. Energy                                               0          7,375,179               0.00                       0.00
WILLOW GLEN 1 - UPP from EGSL Desig. Energy                                        0          4,754,050               0.00                       0.00
WILLOW GLEN 4 - UPP from EGSL Desig. Energy                                        0         17,572,900               0.00                       0.00
LEWIS CREEK 1 Desig. Energy                                               34,239,525                  0               0.00                       0.00
SABINE 1 Desig. Energy                                                     7,107,000                  0               0.00                       0.00
SABINE 2 Desig. Energy                                                    23,850,425                  0               0.00                       0.00
SABINE 3 Desig. Energy                                                    37,222,050                  0               0.00                       0.00
SABINE 5 Desig. Energy                                                    24,519,725                  0               0.00                       0.00
Equalized Res. Charge                                                              0                  0               0.00               1,367,258.30
Trans. Equal. Charge                                                               0                  0               0.00                 698,289.82
Rev 1st QTR - AECC Excess Purchases                                                0                  0               0.00                      (1.37)
Rev 1st QTR - AECC Excess Purchases KWH                                            0                (36)              0.00                       0.00
Rev 1st QTR - Exch Energy Purchases                                                0                  0               0.00                 (87,690.56)
Rev 1st QTR - Exch Energy Purchases KWH                                            0         (2,769,637)              0.00                       0.00
Rev 1st QTR - Exch Energy Sales                                                    0                  0         240,856.44                       0.00
Rev 1st QTR - Exch Energy Sales KWH                                        6,320,297                  0               0.00                       0.00
Rev 1st QTR - Reserve Equalization ETI                                             0                  0               0.00                   3,308.05
Rev 1st QTR - Transmission Equalization ETI                                        0                  0               0.00                   2,317.68
Reverse MSS-1 Revision Estimate Other Prod Units 2005-2011                         0                  0               0.00                (162,768.87)
Reverse MSS-2 Dec 2011 Revision Entries                                            0                  0               0.00              (3,141,688.52)
Revise MSS-1 Other Prod Units 2005-2011                                            0                  0               0.00                 162,756.25
Revise MSS-2 1996-2011                                                             0                  0               0.00               3,140,796.09

Subtotal Purchases and Sales - Associated Companies                     154,844,831         498,388,666       1,156,134.86               4,819,972.98



Non-Associated Companies - Joint Account Sales                       Sales(KWH)         Purchases(KWH)     Revenue($)              Expense($)

Net Balance for Sales                                                              0                  0         (29,300.71)                        0.00
Energy Supp. for Sales                                                     4,469,712                  0         190,214.01                         0.00
CENTRAL LA ELEC CO ENG CHG ADJ - REVENUE                                           0                  0              (0.05)                        0.00
DOW CHEMICAL - GEN REG                                                             0                  0              82.70                         0.00
DUKE ENERGY HINDS - GEN REG                                                        0                  0           1,602.22                         0.00
DUKEENERGY HOTSPRING - GEN REG                                                     0                  0           3,088.58                         0.00
Rev 1st QTR - Net Balance - ETI Demand Sales                                       0                  0              (3.52)                        0.00
Rev 1st QTR - Net Balance - ETI Energy Sales                                       0                  0          (1,436.89)                        0.00
Rev 1st QTR - Off-System Sales ETI                                                 0                  0         (10,740.30)                        0.00
Rev 1st QTR - Off-System Sales ETI KWH                                      (200,466)                 0               0.00                         0.00
Rev 1st QTR - Sales ETI Ann Fee                                                    0                  0          (1,440.75)                        0.00
Rev 1st QTR - Sales ETI Gen Reg                                                    0                  0          (2,344.02)                        0.00
TENASKA FRONTIER - GEN REG                                                         0                  0             571.71                         0.00

Subtotal Non-Associated Companies - Joint Account Sales                    4,269,246                  0         150,292.98                         0.00



Non-Associated Companies - Joint Account Purchases                   Sales(KWH)         Purchases(KWH)     Revenue($)              Expense($)

AECI RE Energy                                                                     0            597,490                 0.00                22,200.35
CALPINE ENERGY SERVICES L.P. RE Energy                                             0            889,366                 0.00                27,953.66
CONOCOPHILLIPS COMPANY RE Energy                                                   0          2,500,000                 0.00                82,950.00
CONSTELLATION ENERGY COMMODITIES GROUP INC RE Energy                               0              8,475                 0.00                   110.17
Caldwell RE Energy                                                                 0            511,269                 0.00                26,779.85
DOW PIPELINE COMPANY RE Energy                                                     0          1,445,500                 0.00                49,803.09
DUKE ENERGY HINDS RE Energy                                                        0             19,672                 0.00                   371.45
DUKEENERGY HOTSPRING RE Energy                                                     0             15,235                 0.00                   337.79
ETEC EXCESS-HRSNHRDN RE Energy                                                     0            167,816                 0.00                 3,490.73
Attachment Snapshot: 20120328074717                             RunID: 23533                                             Billing Snapshot: 20120327102551

                                                                                                                                              99
Exhibit MPC-R-11
Docket No. 39896
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             100
Exhibit MPC-R-11
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             101
Exhibit MPC-R-11
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             102
Exhibit MPC-R-11
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             103
Exhibit MPC-R-11
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             104
Exhibit MPC-R-11
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             105
Exhibit MPC-R-11
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             106
Exhibit MPC-R-11
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             107
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             108
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            109
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            110
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            111
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            112
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            113
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            114
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            115
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            116
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            117
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            118
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            119
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            120
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            121
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            122
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            123
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            124
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            125
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            126
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            127
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            128
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            129
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            130
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            131
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            132
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            133
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            134
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            135
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            136
                                SOAH Docket No. XXX-XX-XXXX
                                         PUC Docket No. 39896
                                            ETI 2011 Rate Case
                                            ETI EXHIBIT NO. 47
                  SOAH DOCKET NO. XXX-XX-XXXX
                       DOCKET NO. 39896


APPLICATION OF ENTERGY         §
TEXAS, INC. FOR AUTHORITY TO   §             BEFORE THE
CHANGE RATES, RECONCILE        §           STATE OFFICE OF
FUEL COSTS, AND OBTAIN         §       ADMINISTRATIVE HEARINGS
DEFERRED ACCOUNTING            §
TREATMENT                      §




                     REBUTTAL TESTIMONY


                               OF


                      ROBERT R. COOPER


                         ON BEHALF OF


                     ENTERGY TEXAS, INC.




                          APRIL 2012




                                                                 1
                          ENTERGY TEXAS, INC.
               REBUTTAL TESTIMONY OF ROBERT R. COOPER
                         PUC DOCKET NO. 39896


                              TABLE OF CONTENTS
                                                                         Page

I.     Introduction                                                          1

II.    Purpose of Rebuttal Testimony                                         1

III.   Rate Year Purchased Power                                             2

        A.   Intervenor Adjustments to Rate Year Purchased Power
              are Not Supported by the Facts of This Case                     3

        B.   Adjustments to Affiliate Purchases                             14

        C.   Adjustments to the 2013 EAI-WBL MSS-4 PPA                      15

IV.    Depreciation and Life of Plant                                       20



                                     EXHIBITS



Exhibit RRC-R-1             2013 EAI-ETI WBL MSS-4 Agreement

Exhibit RRC-R-2             Operating Committee Minutes Pertaining to 2013
                            EAI-WBL Highly Sensitive




                                                                              2
                                                                                    Page 1 of 21
     Entergy Texas, Inc.
     Rebuttal Testimony of Robert R. Cooper
     Docket No. 39896


1                                    I.       INTRODUCTION

2    Q.      PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.

3    A.      My name is Robert R. Cooper.              My business address is Entergy

4            Services, Inc., Parkwood II Building, Suite 300, 10055 Grogan’s Mill Road,

5            The Woodlands, Texas 77380.

6

7    Q.      ARE     YOU       THE   ROBERT      R.   COOPER       WHO      FILED     DIRECT

8            TESTIMONY IN THIS CASE ON NOVEMBER 30, 2011?

9    A.      Yes, I am.

10

11                       II.    PURPOSE OF REBUTTAL TESTIMONY

12   Q.      WHAT IS THE PURPOSE OF THIS TESTIMONY?

13   A.      I provide Rebuttal Testimony on behalf of ETI responding to intervenor

14           testimony on the subjects set forth below:

15                   x   Company’s rate year Purchased Power Expenses –

16                       The Direct Testimony of Cities witnesses Dr. Dennis W. Goins

17                       and Karl J. Nalepa and Texas Industrial Energy Consumers

18                       witness Jeffry Pollock recommending adjustments to rate year

19                       purchased power expense;1 and




     1
          Direct Testimony of Dr. Dennis Goins at pp. 13-19; Direct Testimony of Karl Nalepa at
          pp. 7-18; and Direct Testimony of Jeffry Pollock at pp. 21-27.




                                                                                              3
                                                                              Page 2 of 21
     Entergy Texas, Inc.
     Rebuttal Testimony of Robert R. Cooper
     Docket No. 39896


1                     x   Depreciation, Life of Plant — The Direct Testimony of Cities

2                         witness Jacob Pous on the service life for the Sabine Units 4

3                         and 5.2

4                     With respect to Mr. Pollock’s disallowance of costs associated with

5             the 2013 EAI-WBL MSS-4, I provide as Exhibit RRC-R-1, attached to my

6             rebuttal testimony, a signed copy of that PPA, not available at the time of

7             the filing of my Direct Testimony on November 30, 2011.

8

9                           III.    RATE YEAR PURCHASED POWER

10   Q.       DO YOU HAVE AN OVERARCHING COMMENT ON THE COMPANY’S

11            RATE        YEAR      PURCHASED          POWER   EXPENSE     PRIOR      TO

12            ADDRESSING EACH OF THE INTERVENORS’ RECOMMENDATIONS

13            ON THIS SUBJECT?

14   A.       Yes. The intervenors’ proposed disallowances should be rejected. My

15            Direct Testimony demonstrates that the capacity costs reflected in Exhibit

16            RRC-1 (revised) that are associated with the three new contracts entered

17            into since the test year (with Calpine Energy Services, L.P. [485 MW],

18            Sam Rayburn Municipal Power Agency [225 MW] and Entergy Arkansas,

19            Inc. for its Wholesale Baseload resources [186 MW]) are known and

20            measurable post-test year expenses. Power will be taken under those

21            contracts during the rate year and ETI customers will obtain the production


     2
          Direct Testimony of Jacob Pous at pp. 5-9.




                                                                                        4
                                                                                      Page 3 of 21
     Entergy Texas, Inc.
     Rebuttal Testimony of Robert R. Cooper
     Docket No. 39896


1            cost savings and reliability benefits afforded by those contracts.

2            Additionally, no intervenor witness has challenged the Company’s need

3            for these new rate year contracts. Neither has any intervenor witness

4            challenged the processes that resulted in these contracts or the

5            reasonableness of the prices reflected in these contracts. Nevertheless,

6            the intervenors’ and Staff’s positions regarding the Company’s rate year

7            capacity costs range from no disallowance by the Staff to $33.1 million by

8            Cities witnesses Goins and Nalepa, and $39.4 million by TIEC witness

9            Pollock. The proposed disallowances produce the anomalous result of

10           denying the Company cost recovery even though the prudence of the

11           underlying contracts has not been challenged and the benefits of those

12           contracts will flow exclusively to ETI’s customers.

13

14   A.       Intervenor Adjustments to Rate Year Purchased Power are Not Supported
15                                    by the Facts of This Case

16   Q.      TURNING TO INTERVENORS’ LOAD GROWTH ARGUMENTS,3 DOES

17           YOUR REBUTTAL TESTIMONY RELATE TO TESTIMONY THAT WILL

18           BE FILED BY OTHER REBUTTAL WITNESSES FOR THE COMPANY?

19   A.      Yes. Company witness Phillip R. May addresses intervenors’ load growth

20           arguments in greater detail than I do here.               My testimony supports




     3
          Direct Testimony of Dennis Goins at pp. 15-19; Direct Testimony of Karl Nalepa at p. 8 et
          seq.; Direct Testimony of Jeffry Pollock at p. 23.




                                                                                                 5
                                                                                          Page 4 of 21
     Entergy Texas, Inc.
     Rebuttal Testimony of Robert R. Cooper
     Docket No. 39896


1             Mr. May’s Rebuttal Testimony; specifically, I confirm that ETI is, indeed,

2             short of capacity to serve its existing as well as its projected load.

3                     The intervenors’ load growth arguments are based on a

4             fundamental premise that the difference in unit volume between test year

5             capacity purchases and rate year capacity purchases directly correlates to

6             growth in load served.4 If that premise were correct, one would expect the

7             level of resources acquired for the rate year to exceed the test year

8             capacity requirements (i.e., load plus reserves).5 In fact, that situation

9             does not exist. Intervenors’ underlying premise for their positions is not

10            supported by the facts of this case, causing their load growth arguments to

11            be fatally flawed.

12

13   Q.       PLEASE EXPLAIN HOW THE PREMISE OF THE INTERVENORS’ LOAD

14            GROWTH ARGUMENTS IS NOT SUPPORTED BY THE FACTS OF

15            THIS CASE.

16   A.       During the test year System peak, ETI controlled 3,344 MW of resources;

17            however, its capacity requirement was 4,060 MW, resulting in a deficit of

18            over 700 MW. During the rate year, ETI will control approximately 3,900

19            MW of resources; however, its capacity requirement will be approximately

20            4,300 MW reflecting a capacity deficit of approximately 400 MW. Thus,


     4
          E.g., Direct Testimony of Jeffry Pollock at p. 23: “Rate year purchases reflect the fact that
          ETI is projecting to serve additional load during the Rate Year.”
     5
          Also referred to as Capability Responsibility in the System Agreement.




                                                                                                     6
                                                                             Page 5 of 21
     Entergy Texas, Inc.
     Rebuttal Testimony of Robert R. Cooper
     Docket No. 39896


1           the resources that ETI will control during the rate year (3,900 MW),

2           including the new PPAs I address in my Direct Testimony, are insufficient

3           to cover both ETI’s test year capacity requirement (4,060 MW) and its rate

4           year capacity requirement (4,300 MW). This means that ETI would need

5           to acquire additional capacity for the rate year regardless of any potential

6           growth in load. The intervenors’ intimation that ETI is acquiring post-test

7           year capacity simply to serve anticipated new loads is just wrong.

8                   In summary, ETI is currently short of capacity and would need the

9           rate year purchases enumerated in my Exhibit RRC-1 even if ETI load did

10          not grow from the test year to the rate year.

11

12   Q.     WHAT ARE THE REASONS FOR THE COMPANY’S SHORT POSITION,

13          REQUIRING IT TO ACQUIRE NEW CONTRACTS TO SERVE EXISTING

14          LOAD?

15   A.     There are two main reasons.          First, the Company has historically

16          experienced load growth in its service territory. Second, this load growth

17          occurred during a period of time—including much of the last thirteen

18          years—when the Company was under a regulatory directive to position




                                                                                       7
                                                                                             Page 6 of 21
     Entergy Texas, Inc.
     Rebuttal Testimony of Robert R. Cooper
     Docket No. 39896


1             itself for retail competition.6         That directive resulted in the Company

2             foregoing long-term resource procurement. Thus, a shortfall in resources

3             developed as the Company’s load grew, but ETI relied on the resources of

4             other Entergy Operating Companies (through Service Schedule MSS-1),

5             as well as short-term and limited-term purchases to meet that growing

6             demand. After the obligation to prepare for retail competition was lifted in

7             2009, ETI began the process of adding resources to fill the shortfall that

8             had developed over the years.                That process has been undertaken

9             pursuant to the Entergy System’s planning principles and objectives –

10            discussed in my Direct Testimony – to develop a robust portfolio of

11            resources.       The fact of the matter is that ETI, while it has added

12            resources, still does not own or control sufficient resources to serve its

13            capacity requirements.

14

15   Q.       ARE THERE OTHER REASONS WHY THE DIFFERENCE IN VOLUME

16            BETWEEN TEST YEAR CAPACITY PURCHASES AND RATE YEAR

17            CAPACITY PURCHASES IS NOT REFLECTIVE OF GROWTH IN LOAD?



     6
          See PURA Ch. 39 requiring retail competition in 2002 (adopted 1999); Staff’s Petition to
          Determine Readiness for Retail Competition in the Portions of Texas within the Southeastern
          Reliability Council, Docket No. 24469 (Dec. 20, 2001) (delaying and setting conditions on the
          Company’s transition to retail competition); Application of Entergy Gulf States, Inc. for
          Certification of an Independent Organization for the Entergy Settlement Area in Texas,
          Docket No. 28818 (July 12, 2004) (further delaying and setting conditions on the Company’s
          transition to retail competition; PURA Ch. 39, Subchapter J (deferring the Company’s
          transition to retail competition in 2005 and lifting the obligation to continue the transition to
          retail competition in 2009).




                                                                                                         8
                                                                                       Page 7 of 21
     Entergy Texas, Inc.
     Rebuttal Testimony of Robert R. Cooper
     Docket No. 39896


1    A.      Yes. Consistent with the Strategic Resource Plan discussed in my Direct

2            Testimony, the Company’s long-term resource procurement strategy,

3            sometimes referred to as the “Portfolio Transformation Strategy,”7 seeks to

4            develop a more diverse, modern, and efficient portfolio of generation

5            supply resources to meet customer needs. This strategy is not limited to

6            procurement of resources necessary to serve growth in load. Rather, this

7            strategy is designed to transform the System’s portfolio of resources used

8            to serve existing loads as well as future demand.                  Specifically, this

9            strategy is implemented to align both the amount of resources needed to

10           serve load with the type of resources that can most economically serve

11           load. The type of resource used to serve load is determined by customer

12           load shape requirements, and the objective is to obtain a mix of resources

13           that can economically serve a variety of supply roles. In addition, the

14           strategy seeks to maintain the existing generation and power supply

15           resources of the Entergy Operating Companies to meet the capability

16           needs of the System, when economically justified. The resulting portfolio

17           will meet planning objectives in a balanced manner by providing reliable,

18           cost effective, and more stably-priced power, while providing the

19           operational flexibility to follow load and respond to operating constraints

20           and supply contingencies.


     7
          The Portfolio Transformation Strategy is discussed in the current Strategic Resource Plan,
          which was provided to parties in response to TIEC 1-18, provided again as WP/RRC-R/3.
          See pp. 1-3 and 11-1.




                                                                                                  9
                                                                                          Page 8 of 21
     Entergy Texas, Inc.
     Rebuttal Testimony of Robert R. Cooper
     Docket No. 39896


1                     Thus, consistent with the Portfolio Transformation Strategy, new

2             resources can be added to better serve existing loads. The Company’s

3             new rate year contracts achieve these objectives to more economically

4             serve loads by providing lower-cost energy, which energy savings are

5             passed through to customers via reduced fuel costs.8

6

7    Q.       WHAT       IS     YOUR       UNDERSTANDING               OF      MR.     POLLOCK’S

8             ADJUSTMENT           TO      THE      COMPANY’S           PURCHASED           POWER

9             EXPENSE?

10   A.       In each of the categories of purchased power (Third Party purchases,

11            Affiliate purchases, Reserve Equalization), Mr. Pollock ignores the

12            increase in the amount of MW procured between the test year and the rate

13            year. Instead, he holds the amount (using a megawatts per month metric)

14            the same and adjusts only the rate for purchased power, applying the rate

15            year unit cost rate to the test year number of units.

16

17   Q.       DO YOU AGREE WITH THIS ADJUSTMENT?

18   A.       No.    As discussed above, his adjustments are based on the faulty

19            assumption that incremental MWs purchased are reflective of growth in

20            load. As I have explained above, the new contracts are not sufficient to


     8
          See the cost/benefit analyses supporting the rate year contracts presented in Schedule I-15 –
          Entergy Operating Committee Minutes for 2/26/2010; 6/18/2010; 10/15/2010; 3/18/2011;
          4/19/2011; see also Highly Sensitive Exhibit RRC-R-2.




                                                                                                    10
                                                                                 Page 9 of 21
     Entergy Texas, Inc.
     Rebuttal Testimony of Robert R. Cooper
     Docket No. 39896


1           meet ETI’s existing capacity requirements and they were not contracted

2           for the sole purpose of satisfying potential growth in load.

3                   Also, as noted above, the prudence of these contracts has not been

4           challenged. Mr. Pollock’s adjustment results in ETI’s customers receiving

5           the production cost and reliability benefits provided by the full level of MW

6           associated with the new contracts (because they have been contracted

7           for), but does not reflect the attendant capacity costs associated with the

8           full level of MWs that provide benefits customers will obtain.

9                   Additionally, Mr. Pollock assumes that the distribution of costs

10          between      third-party    purchases,     affiliate   purchases   and   reserve

11          equalization purchases would remain the same regardless of the known

12          and measurable changes in the purchase agreements. This approach

13          ignores the fact that the new lower energy cost third-party contracts and

14          affiliate contracts will make up a greater portion of ETI’s supply mix (again,

15          because they have been contracted for), which has the effect of reducing

16          the Company’s reliance on Reserve Equalization. Even if the total level of

17          MWs purchased remained the same as in the test year, the allocation of

18          purchases between resources must reflect the amounts contracted (i.e.,

19          there will be more MW controlled by contract and less reliance on Reserve

20          Equalization). Just this change in the allocation of costs would reduce Mr.

21          Pollock’s adjustment by $12,688,000.9


     9
         See WP/RRC-R/1, which is a modified Exhibit JP-1.




                                                                                          11
                                                                        Page 10 of 21
     Entergy Texas, Inc.
     Rebuttal Testimony of Robert R. Cooper
     Docket No. 39896


1    Q.     WHAT DO MR. POLLOCK’S LOAD GROWTH NUMBERS REPRESENT?

2    A.     Mr. Pollock represents “load growth” in megawatts per month (“MW-Mo”)

3           of purchased capacity. This metric that he has developed appears to be

4           intended to represent the amount of capacity that has been purchased by

5           the Company for each month of the year plus the amount of Reserve

6           Equalization capacity that is required each month to meet the Company’s

7           capacity requirement.

8

9    Q.     IS AN INCREASE IN CAPACITY PURCHASES MEASURED IN MR.

10          POLLOCK’S TERMS OF MW-MO A VALID REPRESENTATION OF

11          LOAD GROWTH?

12   A.     No. The volume of purchases in terms of MW-Mo is only reflective of the

13          type and quantity of purchases needed to fill ETI’s minimum monthly

14          capacity requirement and is not directly reflective of load growth.

15          Changes in the MW-Mo volume of purchases can be caused by a number

16          of factors that are unrelated to load growth such as changes in owned

17          capability and changes in the timing, type and mix of purchases. For

18          example, ETI could derate a unit for an extended period for operational

19          reasons and replace that capacity with a purchase, thereby creating more

20          MW-Mo of purchases per Mr. Pollock. In that situation, Mr. Pollock would

21          assume that such purchase would be representative of load growth even

22          though no such growth occurred.




                                                                                  12
                                                                            Page 11 of 21
     Entergy Texas, Inc.
     Rebuttal Testimony of Robert R. Cooper
     Docket No. 39896


1                   Mr. Pollock’s application of his MW-Mo metric to Reserve

2           Equalization also demonstrates the flaw in that metric. The amount of

3           Reserve Equalization purchases in the mix of total purchases has a

4           particularly large effect on the total MW-Mo volume. This is due to the fact

5           that Reserve Equalization capacity purchases vary by month based on the

6           monthly System capability and load responsibility.       That variation in

7           Reserve Equalization can occur even though there is no change in ETI’s

8           load. For example, another Operating Company may add a new resource

9           that has the effect of lowering that Operating Company’s “short” position

10          and increasing ETI’s “short” position.    In that situation, ETI’s Reserve

11          Equalization payments would increase, and Mr. Pollock would identify

12          more MW-Mo and attribute the increase in MW-Mo to load growth even

13          though there was no change in ETI’s load.

14                  In sum, Mr. Pollock’s MW-Mo metric appears to be one that he has

15          fabricated to support his theory on the effect of load growth.       I have

16          demonstrated that his metric grossly oversimplifies and misrepresents the

17          Company’s position with respect to loads and resources. It should not be

18          relied on to support adjustments to the Company’s purchased power

19          expense.




                                                                                      13
                                                                                       Page 12 of 21
     Entergy Texas, Inc.
     Rebuttal Testimony of Robert R. Cooper
     Docket No. 39896


1    Q.       DO YOU AGREE WITH MR. NALEPA’S ADJUSTMENT TO RATE YEAR

2             PURCHASED POWER EXPENSE?

3    A.       No. While Mr. Nalepa uses a recognized metric (kW) in his analysis, he

4             employs the same faulty assumption that each incremental kW purchased

5             above the test year level is associated with an increment of load above

6             that in the test year.10 As I discuss above, that is not the case.

7                     Also, like Mr. Pollock, Mr. Nalepa proposes to limit the volume

8             (MW) of purchases to a test year level even though he uses a rate year

9             average cost.       As I explained above, this would have the effect of

10            providing the capacity benefit of the purchases to customers, including

11            production cost benefits, associated with the full volume of purchases.

12            However, customers would only bear a portion of the costs necessary to

13            obtain those benefits.

14

15   Q.       MR. NALEPA ADVOCATES THAT THE COMPANY’S ADJUSTMENTS

16            TO TEST YEAR PURCHASED POWER EXPENSES FOR KNOWN AND

17            MEASURABLE RATE YEAR CONTRACTS SHOULD BE REJECTED

18            BECAUSE NOT ALL ATTENDANT IMPACTS ARE REFLECTED.11 IS

19            MR. NALEPA CONSISTENT IN HIS ADVOCACY?




     10
          Direct Testimony of Karl Nalepa at pp. 9-10 and 11 “The Company is contracting for capacity
          resources to meet future demand.”
     11
          Direct Testimony of Karl Nalepa at p. 12.




                                                                                                  14
                                                                             Page 13 of 21
     Entergy Texas, Inc.
     Rebuttal Testimony of Robert R. Cooper
     Docket No. 39896


1    A.       No. Mr. Nalepa recommends that rate year purchased power costs for

2             third-party purchases and the 2013 EAI-WBL be reduced to reflect test

3             year levels.    At the same time, he recommends that the Commission

4             approve the rate year level of Reserve Equalization costs (MSS-1), which

5             is a reduction compared to the test year.12 Thus, Mr. Nalepa opposes cost

6             increases associated with the rate year but favors cost decreases

7             associated with the rate year. Mr. Nalepa fails to acknowledge that the

8             reduction in Reserve Equalization costs from the test year to the rate year

9             is an attendant impact of the increase in third-party and the 2013 EAI-WBL

10            purchases during the rate year. This is because ETI relies less on the

11            resources of other Operating Companies through Reserve Equalization

12            when it adds to the resources it controls (i.e., ETI becomes less “short”).

13            Thus, if Mr. Nalepa recommends that the Commission not recognize the

14            addition of resources in the rate year, he should have been consistent with

15            his principle of reflecting attendant impacts and recognized a greater

16            reliance on the resources of other Operating Companies consistent with

17            the test year level of Reserve Equalization expense (i.e., a larger “short”

18            position).




     12
          Id. at pp. 16-17.




                                                                                       15
                                                                                Page 14 of 21
     Entergy Texas, Inc.
     Rebuttal Testimony of Robert R. Cooper
     Docket No. 39896


1                          B.      Adjustments to Affiliate Purchases

2    Q.     DR. GOINS ADJUSTED THE HISTORICAL TIME PERIOD FOR

3           DETERMINING            MSS-4      PPA   COSTS    FOR        ETI’S   AFFILIATE

4           CONTRACTS, AS COMPARED TO YOUR DETERMINATION OF THOSE

5           COSTS FOR EXHIBIT RRC-1. PLEASE DESCRIBE HIS ADJUSTMENT.

6    A.     As discussed in my Direct Testimony, my Exhibit RRC-1 included affiliate

7           contracts (both “legacy” and “other”), by which ETI purchased capacity

8           and energy from a generating resource owned or controlled by another

9           Operating Company. Such sales from one Entergy Operating Company to

10          another are provided for and governed under Service Schedule MSS-4 of

11          the Entergy System Agreement. For the purpose of projecting capacity

12          costs reflected in Exhibit RRC-1, I used an average of the capacity costs

13          for the most recent 12-month period for these contracts, which was the

14          period September 2010 through August 2011.           Dr. Goins updated the

15          historical 12-month period for determining capacity costs to the period of

16          November 2010 through October 2011.             His adjustments purportedly

17          resulted in a reduction of $4.7 million to the requested amount for Legacy

18          Affiliate contracts.

19

20   Q.     DO YOU AGREE WITH DR. GOINS’ UPDATED ADJUSTMENTS?

21   A.     No.     Dr. Goins erred in his calculations.      For example, Dr. Goins’

22          adjustments do not take into account the amounts for nuclear




                                                                                          16
                                                                                Page 15 of 21
     Entergy Texas, Inc.
     Rebuttal Testimony of Robert R. Cooper
     Docket No. 39896


1               decommissioning associated with River Bend Station. He has also simply

2               added the wrong numbers with respect to Willow Glen 2.                In his

3               workpaper, Dr. Goins added the “date” line and mischaracterized the

4               results of that calculation as capacity costs. The “date” line only indicates

5               the month and year in which the costs were incurred. It does not reflect

6               the level of capacity costs incurred.

7

8                      C.     Adjustments to the 2013 EAI-WBL MSS-4 PPA

9    Q.         DO YOU AGREE WITH MR. NALEPA’S NORMALIZATION OF THE 2013

10              EAI-WBL MSS-4 PPA OVER A THREE-YEAR PERIOD?

11   A.         No. Mr. Nalepa proposes that half the EAI-WBL rate year expense be

12              included in rates based on his speculation the 2013 EAI-WBL agreement

13              “will expire half way through the expected period that the rates will be [in]

14              effect . . . ”13 I cannot validate Mr. Nalepa’s speculation, as I have no way

15              of knowing how long the proposed rates will be in effect. However, I can

16              say that Mr. Nalepa’s conclusion that his adjustment “ensures that the

17              Company collects in rates only the capacity expenses that it actually

18              incurs”14 is plain wrong because that conclusion fails to account for the

19              outcome of prudent procurement practices. Mr. Nalepa fails to recognize

20              that ETI continues to be short of resources and must secure new

21              resources as the terms of existing purchased resources expire. Upon its
     13
          Direct Testimony of Karl Nalepa at p. 16.
     14
          Id.




                                                                                          17
                                                                                Page 16 of 21
     Entergy Texas, Inc.
     Rebuttal Testimony of Robert R. Cooper
     Docket No. 39896


1             expiration in December 2013, the 2013 EAI-WBL MSS-4 PPA will be

2             replaced by other resources or a concomitant increase in Reserve

3             Equalization charges. Thus, ETI will incur capacity costs for replacement

4             resources after the 2013 EAI-WBL contract expires. If, on the other hand,

5             Mr. Nalepa expects that ETI will secure replacement resources when the

6             2013 EAI-WBL expires, his adjustment has the effect of assuming that ETI

7             will be able to substitute resources of equivalent capacity for half the cost

8             of the rate year amount, which is an unreasonable and unsupported

9             assumption. Furthermore, under his approach, ETI rates will be set at a

10            level that realizes the full MSS-1 benefit of the EAI-WBL resources

11            (i.e., reduced reliance on the resources of other Operating Companies and

12            a relatively smaller “short” position), while only shouldering a portion of the

13            costs necessary to obtain the benefit.

14

15   Q.       WHAT IS MR. POLLOCK’S TESTIMONY WITH RESPECT TO THE 2013

16            EAI-WBL MSS-4 PPA?

17   A.       Mr. Pollock’s recommendation is that the 2013 EAI WBL MSS-4 PPA

18            should not be included for recovery in rates set in this case, because “ETI

19            has not yet submitted a new EAI-WBL PPA for Commission review, and

20            Commission review is essential to determine whether this agreement is

21            prudent.”15


     15
          Direct Testimony of Jeffry Pollock at 26.




                                                                                          18
                                                                            Page 17 of 21
     Entergy Texas, Inc.
     Rebuttal Testimony of Robert R. Cooper
     Docket No. 39896


1                   Mr. Pollock ultimately provides an alternative adjusted amount for

2           this contract which I address below.

3

4    Q.     HOW DO YOU RESPOND TO MR. POLLOCK’S RECOMMENDATION

5           TO IGNORE 2013 EAI-WBL MSS-4 PPA?

6    A.     Mr. Pollock’s recommendation lacks merit. In its first addendum to the

7           response to TIEC 5-1, produced on March 7, 2012, ETI provided the

8           minutes to the March 2, 2012 Entergy Operating Committee meeting,

9           which included, and attached, a presentation regarding this purchase,

10          setting forth the case for EAI and ETI entering into the contract, as well as

11          the information regarding the costs for this purchase to ETI. See Highly

12          Sensitive Exhibit RRC-R-2.        Those minutes note that the Operating

13          Committee approved the material terms of the proposed transaction.

14          Notably, Mr. Pollock did not challenge the prudence of the contract.

15          Apparently, however, Mr. Pollock is complaining that the actual signed

16          MSS-4 contract document had not been made part of the filing in this

17          docket (even though the necessity to have a contract in place to file as a

18          rate schedule with the Federal Energy Regulatory Commission has not yet

19          arisen). I consider this form over substance, in that the Entergy Operating

20          Committee had approved the 2013 EAI-WBL MSS-4 PPA, and EAI and

21          ETI had agreed to the substantive terms of that transaction. Additionally,

22          the signed contract provides no more information regarding its terms than




                                                                                      19
                                                                            Page 18 of 21
     Entergy Texas, Inc.
     Rebuttal Testimony of Robert R. Cooper
     Docket No. 39896


1            was included in the documents previously produced to the parties. Be that

2            as it may, I am attaching as my Exhibit RRC- R-1 a signed copy of the

3            2013 EAI WBL MSS-4 PPA, which addresses the concerns raised by Mr.

4            Pollock.

5

6    Q.      PLEASE ADDRESS MR. POLLOCK’S QUANTIFICATION OF HIS

7            RECOMMENDATION TO DISALLOW THE ENTIRETY OF THE 2013

8            EAI-WBL MSS-4 PPA.

9    A.      Similar to Mr. Pollock’s adjustment for all purchased power costs,

10           discussed above, his adjustment for the 2013 EAI-WBL MSS-4 PPA, as

11           reflected in his Exhibit JP-2, incorporates a quantity for MW-months which

12           is less than that provided for in that contract.   Mr. Pollock’s proposed

13           adjustment is in error in that he incorrectly removes the 2013 EAI-WBL

14           contract for seven months during the rate year, where only five months

15           (January through May) are in the rate year and are therefore subject to the

16           new EAI WBL agreement for that period of time.          This results in a

17           $3,059,000 error in Mr. Pollock’s recommended disallowance.16 However,

18           this issue alone only addresses an error in his calculation. As discussed

19           above, I disagree with the substance of his recommendation.




     16
          See WP/RRC-R/2, which is a modified Exhibit JP-2.




                                                                                      20
                                                                              Page 19 of 21
     Entergy Texas, Inc.
     Rebuttal Testimony of Robert R. Cooper
     Docket No. 39896


1    Q.       DO YOU HAVE CONCERNS WITH MR. POLLOCK’S ALTERNATIVE

2             RECOMMENDATION17 TO DISALLOW ONLY A PORTION OF THE 2013

3             EAI-WBL MSS-4 PPA?

4    A.       Yes.     In this alternative, Mr. Pollock also carries forward his error

5             concerning the term of the EAI-WBL agreement, and calculates a seven-

6             month potential disallowance for the rate year. This causes a $1,679,000

7             error in the calculation of his alternative recommendation.18

8

9    Q.       DO YOU HAVE ANY OTHER CONCERNS WITH MR. POLLOCK’S

10            ALTERNATIVE RECOMMENDATION TO DISALLOW A PORTION OF

11            THE 2013 EAI-WBL MSS-4 PPA?

12   A.       Yes. Mr. Pollock inexplicably uses a quantity reflecting the lower amount

13            of MW provided in the existing EAI-WBL contract and does not reflect the

14            full value the new contract for the period of January through May 2013.

15            His adjustments take credit for the lower per-unit costs of the new

16            agreement while ignoring the increased volume. Mr. Pollock should reflect

17            the full volume of the contract in his calculations, or he should reflect the

18            full costs of the previous contract. He cannot rationally or reasonably pick

19            and choose among the elements of the contracts he likes while casting out

20            those elements he doesn’t like.



     17
          Direct Testimony of Jeffry Pollock at p. 27, Footnote 10.
     18
          See WP/RRC-R/2.




                                                                                        21
                                                                                       Page 20 of 21
     Entergy Texas, Inc.
     Rebuttal Testimony of Robert R. Cooper
     Docket No. 39896


1                         IV.     DEPRECIATION AND LIFE OF PLANT

2    Q.       AT PAGE 6 OF HIS TESTIMONY, CITIES WITNESS POUS CLAIMS

3             THAT ETI HAS NO BASIS FOR THE PROPOSED SIXTY-YEAR

4             DEPRECIABLE LIFE FOR SABINE UNITS 4 AND 5. WHAT IS YOUR

5             RESPONSE?

6    A.       Mr. Pous is incorrect. The sixty-year expected lives for Sabine Units 4

7             and 5 are consistent with current system and ETI resource planning

8             principles and parameters.19          The sixty-year life for these units was

9             provided to Mr. Watson by ESI resource planning personnel, based on the

10            Entergy System Fossil Deactivation Schedule. This schedule reflects an

11            assessment that, based on “a variety of considerations, including age,

12            operational role, level of funding, unit condition, and operational risk,” sixty

13            years constitutes a reasonable “basic threshold” life. In other words, it is

14            reasonable to expect that these plants will be retired no earlier than the

15            age of sixty.20 The Fossil Deactivation Schedule, however, also states

16            that “[t]his is a long-term planning assumption and does not represent a

17            retirement schedule.          These units could possibly migrate to a




     19
          While Mr. Pous is correct that I did not personally provide the Sabine life information to
          Company witness Watson, Mr. Pous also recognizes Mr. Watson’s statement in his
          deposition that the information may well have been provided by generation department
          personnel, without identifying a particular member of that department. Pous Testimony at p.
          6, line 21.
     20
          The plant lives provided by ESI resource planning personnel are reproduced in Appendix D-1,
          page 1 of 1, to Mr. Watson’s depreciation study.




                                                                                                  22
                                                                                  Page 21 of 21
     Entergy Texas, Inc.
     Rebuttal Testimony of Robert R. Cooper
     Docket No. 39896


1               non-operational status in the next 20 years….            The actual timing of

2               deactivation is uncertain and will likely change.”

3                      I would further note that Mr. Pous’ assessment of the Sabine Units’

4               depreciable lives assumes a precision in the estimation of such matters

5               that is not reasonably achievable, given how far off the retirement dates

6               are at this point in time. The sixty-year life for Sabine, however, is a

7               reasonable estimate for present purposes.            Mr. Pous has not shown

8               otherwise; he has simply chosen a somewhat longer life. Moreover, the

9               difference in lifespans between the Sabine Units and Lewis Creek is fully

10              supported by the fact that a major repair program is planned for the latter,

11              but not the former, as discussed by Company witness Winfred W.

12              Garrison. This distinction is expressly noted in the rationale provided to

13              Mr. Watson supporting the longer life for the Lewis Creek Units.21

14

15   Q.         DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY?

16   A.         Yes.




     21
          Id.




                                                                                            23
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                                         AGREEMENT


       This Agreement is dated as of April II, 2012. between Entergy Arkansas, lnc. ("EAI"

or ·•Seller"), and Entergy Texas, Inc. (''ETI" or ·'Buyer").

        WHEREAS, EAl has agreed to make a unit power sale from the designated units set

forth on Attachment A (individually a '"Designated Unit" and collectively "Designated Units")

to ETI; and

        WHEREAS, the Agreement among EAI, Entergy Gulf States, Inc. ("EGS"), Entergy

Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc. and Entergy Services,

Inc. (hereinafter referred to as the "System Agreement"), was filed with the FERC on April30,

1982, and became effective on January I, 1983, and amended to incorporate EGS in 1993 and

further amended in 2008 to spli t EGS into Entergy Gulf States Louisiana, L.L.C., and Entergy

Texas, Inc.; and

       WHEREAS, by Order dated July 20, 2007, the FERC approved the addition ofEntergy

Gulf States Louisiana, L.L.C., and ETI as parties to the System Agreement; and

       WHEREAS, the System Agreement contains a Service Schedule MSS-4 providing the

basis for making a unit power purchase between the Companies that are participants in that

Agreement; and

       WHEREAS, the parties herein wish to execute this Agreement to provide for a unit

power purchase by ETI under Service Schedule MSS-4 from the Designated Units.

       THEREFORE. the parties agree as follows:

       1.      Unit Power Purchase. T hroughout the delivery term set forth in paragraph 2

below, EAI agrees to sell and ETI agrees to purchase that quantity of generating capacity and

associated energy from the Designated Units equivalent to the percentage (the ··Allocated




                                                                                             24
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Percentage") of EAI 's baseload capacity in each such Designated Unit set forth on Attachment

A.

         2.    Term. Purchases and sales of capacity and energy under this Agreement shall

commence at the beginning of January I, 2013, and shall continue thereafter through the end of

December 18, 2013.

         3.    Pricing. The pricing of the capacity and energy to be sold and purchased

pursuant to paragraph 1 above shall be as specified in Service Schedule MSS-4 of the System

Agreement.

         4.    Energy Entitlement. ETI is entitled to receive on an hourly basis the Allocated

Percentage of the energy generated by each of the Designated Units.

         5.    Termination. Neither party shall have the right to terminate the unit power

purchase and sale required by this Agreement without the express written consent of the other

party.

         6.    Condition Precedent. This Agreement shall be conditioned upon Buyer

receiving all regulatory approvals required by Buyer for this Agreement no later than August I,

2012.

         7.    Notices. Unless specifically stated otherwise herein, any notice to be given

hereunder shall be sent by Registered Mail, postage prepaid, to the party to be notified at the

address set forth below, and shall be deemed given when so mailed.

                      To EAI:         Entergy Arkansas, Inc.
                                      425 West Capitol Avenue
                                      Little Rock, AR 72201
                                      ATIN: Chief Executive Officer

                      To ETI:         Entergy Texas. Inc.
                                      350 Pine Street
                                      Beaumont. TX 7770 I
                                      ATTN: Chief Executive Officer.
                                                2



                                                                                                  25
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        8.      Nonwaiver. The failure of either party to insist upon or enforce. in any instance,

strict performance by the other of any ofthe terms of this Agreement or to exercise any rights

herein conferred or otherwise available to it shall not be considered a waiver or relinquishment

to any extent of its rights to assert or rely upon any such terms or rights on any future occasion.

        9.      Amendments. No waiver, alteration, amendment or modification of any of the

provisions of this Agreement shall be binding unless in writing and signed by a duly authorized

representative of both parties (except for waivers, which require the signature of a duly

authorized representative of only the waiving party).

        10.    Entire Agreement. This Agreement, which is entered into in accordance with

the authority of Service Schedule MSS-4 of the System Agreement, constitutes the entire

agreement and supersedes all previous and collateral agreements or understandings between

the parties with respect to the subject matter hereof.

        11.    Severability. It is agreed that if any clause or provision of this Agreement is

held by the courts to be illegal or void, the validity of the remaining portions and provisions of

the Agreement shall not be affected, and the rights and obligations of the parties shall be

enforced as if the Agreement did not contain such illegal or void clauses or provisions.


                                                         ENTERGY ARKANSAS, INC.

                                                          ~--
                                                         BY: ~
                                                             ~-----
                                                         TITLE:   '/;x.s.   1/ (?UD, ef-rl


                                                         ENTER7~WC :
                                                         BY:~
                                                         TITLE:   Pll.4 fCE"'V         El;t:_

                                                3


                                                                                                  26
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                                               ATfACHMENT A


                                     SALE OF CAPACITY AND E1 ERGY

                       BY ENTERGY ARKANSAS, INC. TO El\TERGY TEXAS. r.-lC.



During the period. January I, 2013 through December 18, 2013. the capacity and energy amount is as follows:

                                   EAI's             EAI's AVAILABLE            BUYER'S           BUYER'S
                                   BASELOAD          BASELOAD                   ALLOCATED         ALLOCATED
                                   CAPACITY*         CAPACITY*                  CAPACITY*
        PERCENTAGE
DESIGNATED UNlTS
ANO Unit2                           989.00            84                          84               I 000/o
White Bluff Unit I                  465.00            39                          39     100%
White Bluff Unit 2                  481.00            41                          41               100%
Independence Unit I                 263.00            22                          22               100%

TOTAL                                                 186                          186             100%


*Expressed in megawans. Whenever and to the extent "EAI's Baseload Capacity" for a Designated Unit
u1creases or decreases, "Buyer's Allocated Capacity" for such Designated Unit shall automatically adjust
correspondingly based on Buyer's Allocated Percentage ofEAI's Baseload Capacity.




                                                       4


                                                                                                              27
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                             ENTERGY TEXAS, INC.
                     PUBLIC UTILITY COMMISSION OF TEXAS
                         SOAH DOCKET NO. XXX-XX-XXXX
                    PUC DOCKET NO. 39896 - 2011 ETI Rate Case

Response of: Entergy Texas, Inc.                 Prepared By: Counsel
to the Fifth Set of Data Requests                Sponsoring Witness: Robert R. Cooper
of Requesting Party: Texas Industrial Energy     Beginning Sequence No.
Consumers
                                                 Ending Sequence No.

Question No.: TIEC 5-1                          Part No.:                Addendum: 2

Question:

Purchased Power Capacity Costs

        ETI’s response to TIEC 1-7 stated that “The EAI WBL limited term power
purchase agreement was assumed to continue through 2013 based on ETI’s need for base
load resources and an offer from EAI to extend the terms of the agreement for one year.”

       a.     Please provide a copy of EAI’s offer, including price, terms, and
              conditions.

       b.     How would the economics of the offer be changed when EAI exits the
              Entergy System Agreement?

       c.     Please provide all documents provided to the Operating Committee
              surrounding EAI’s offer.

       d.     Please provide any minutes of meetings with the Operating Committee
              where EAI’s offer was discussed.

       e.     Please state the status of ETI’s evaluation of EAI’s offer, including
              whether any other base load alternatives were considered.

       f.     Please provide any formal or informal solicitation or other market analysis
              comparing EAI’s offer to other base load resources.

       g.     Please provide a timeline for ETI reaching a decision about the EAI offer.

       h.     Please provide a copy of the signed agreement documenting ETI’s
              acceptance of EAI’s offer.




                                                                                            28
  39896                                                                    TIEC 5-1 Add 2 TH788
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Response:

a.       ETI objects on the basis that documents responsive to this RFI (1) may reflect
         privileged attorney-client communications or work-product, and (2) may be highly
         sensitive protected materials under the Protective Order issued in this docket.
         Subject to the objection, the Company has not located a document or documents
         that include terms of an offer to extend the current “EAI WBL limited term power
         purchase agreement” referred to in the RFI. ESI is proceeding with the evaluation
         of the potential purchase by the Entergy System of capacity and energy from
         certain resources included in EAI’s WBL group of resources pursuant to the terms
         of Service Schedule MSS-4 of the Entergy System Agreement, to begin in January
         2013, which, if authorized by the Entergy Operating Committee, could be
         allocated in whole or in part to ETI.

b, c, d, e, f, g, and h.

         See response to subsection a.

Addendum 1:

The Company objects to this request on grounds that the responsive materials are highly
sensitive protected (“highly sensitive”) materials. Specifically, the responsive materials
are protected pursuant to Texas Government Code Sections 552.101, 552.104 and/or
552.110. Highly sensitive materials will be provided pursuant to the terms of the
Protective Order in this docket.

Please see the attached.

Addendum 2:

The Company objects to this request on grounds that the responsive materials are highly
sensitive protected (“highly sensitive”) materials. Specifically, the responsive materials
are protected pursuant to Texas Government Code Sections 552.101, 552.104 and/or
552.110. Highly sensitive materials will be provided pursuant to the terms of the
Protective Order in this docket.

Please see the attached CD containing the February 17, 2012 highly sensitive presentation
to the Entergy Operating Committee. The minutes of the Entergy Operating Committee
(and the associated presentation) reflecting the Operating Committee’s decision regarding
the 2013 Wholesale Baseload transaction have been previously produced.




                                                                                             29
     39896                                                                  TIEC 5-1 Add 2 TH789
                                                                          Exhibit RRC-R-2
                                                                        Docket No. 39896
                                                             Page 3 of 34 through 34 of 34
                                                                           (Public Version)




       This exhibit contains information that is highly sensitive and will be provided

under the terms of the Protective Order (Confidentiality Disclosure Agreement) entered

in this case.




                                                                                        30
                                 SOAH Docket No. XXX-XX-XXXX
                                         PUC Docket No. 39896
                                            ETI 2011 Rate Case
                                            ETI EXHIBIT NO. 55
                  SOAH DOCKET NO. XXX-XX-XXXX
                     PUC DOCKET NO. 39896

APPLICATION OF ENTERGY         §
TEXAS, INC. FOR AUTHORITY TO   §             BEFORE THE
CHANGE RATES, RECONCILE        §           STATE OFFICE OF
FUEL COSTS, AND OBTAIN         §       ADMINISTRATIVE HEARINGS
DEFERRED ACCOUNTING            §
TREATMENT                      §




                     REBUTTAL TESTIMONY


                               OF

                      HEATHER G. LEBLANC


                         ON BEHALF OF


                      ENTERGY TEXAS, INC.




                          APRIL 2012




                                                                 1
                         ENTERGY TEXAS, INC.
              REBUTTAL TESTIMONY OF HEATHER G. LEBLANC
                          DOCKET NO. 39896


                               TABLE OF CONTENTS

                                                                      Page

I.      Introduction                                                     1 

        A.    Introduction and Qualifications                            1 

        B.    Purpose of Rebuttal Testimony                              1 

II.     Cost of Service                                                  2 

        A.    Municipal Franchise Fees and Miscellaneous Gross
              Receipt Taxes                                              2 

        B.    COS “Flaw”                                                 3 

        C.    Updated Schedule P to include PPR in Base Rates            4 

        D.    Allocation and Disallowance of Specific Project Codes
              or Accounts                                                4 

        E.    Rebuttal COS Study                                         7 

III.    Renewable Energy Credit Rider                                    8 

IV.     Transmission Cost Recovery Factor and Distribution Cost
        Recovery Factor                                                 13 

V.      Conclusion                                                      14 



                                     EXHIBITS

Exhibit HGL-R-1        Company Response to Staff 17-1

Exhibit HGL-R-2        Rebuttal Summary Cost of Service

Exhibit HGL-R-3        Rebuttal Cost of Service Adjustments

Exhibit HGL-R-4        Renewable Energy Credit Rider




                                                                         2
     Entergy Texas, Inc.                                                     Page 1 of 14
     Rebuttal Testimony of Heather G. LeBlanc
     Docket No. 39896


1                                    I.     INTRODUCTION

2                            A.      Introduction and Qualifications

3    Q.     PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.

4    A.     My name is Heather G. LeBlanc. My business address is 5564 Essen

5           Lane, Baton Rouge, LA 70809. Since filing my direct testimony, my

6           business address has changed.

7

8    Q.     DID YOU PREVIOUSLY FILE DIRECT TESTIMONY ON BEHALF OF

9           ENTERGY TEXAS, INC. (“ETI” OR “THE COMPANY”) IN THIS

10          PROCEEDING?

11   A.     Yes, I did.

12

13   Q.     DO YOU SPONSOR ANY EXHIBITS OR SCHEDULES IN THIS FILING?

14   A.     I sponsor the Exhibits listed in the Table of Contents.

15

16                           B.      Purpose of Rebuttal Testimony

17   Q.     WHAT IS THE PURPOSE OF THIS TESTIMONY?

18   A.     The purpose of my rebuttal testimony is to address several issues in

19          response to Intervernor and Staff direct testimony. First, I will address

20          issues pertaining to the cost of service (COS) model as raised by

21          Intervenor witnesses Pollock, Chriss, and Szerszen as well as discuss and

22          sponsor the Company’s rebuttal COS Study.           Secondly, I will address

23          issues about the Company’s Renewable Energy Credit (“REC”) Rider as



                                                                                       3
     Entergy Texas, Inc.                                                       Page 2 of 14
     Rebuttal Testimony of Heather G. LeBlanc
     Docket No. 39896


1              discussed by Intervenor witnesses Pevoto, Nalepa, and Benedict and

2              Staff witness Abbott.       Next, I will address the establishment of the

3              Transmission Cost Recovery Factor (“TCRF”) and the Distribution Cost

4              Recovery Factor (“DCRF”) as discussed by Mr. Chriss and Cities witness

5              Mr. Brazell.

6

7                                  II.      COST OF SERVICE

8         A.       Municipal Franchise Fees and Miscellaneous Gross Receipt Taxes

9    Q.        MR.    POLLOCK,      ON      BEHALF     OF    TIEC,   MAKES     SEVERAL

10             RECOMMENDATIONS REGARDING TWO ALLEGED “FLAWS” IN THE

11             COMPANY’S COST OF SERVICE STUDY WHEN ALLOCATING

12             MUNICIPAL FRANCHISE FEES AND MISCELLANEOUS GROSS

13             RECEIPTS TAXES (PAGES 51-62).                DO YOU AGREE WITH HIS

14             RECOMMENDATIONS?

15   A.        I do not agree with Mr. Pollock’s recommendation to allocate these costs

16             using a “Direct” method to only customers inside the city limits. It is the

17             Company’s position that these costs should be allocated to the rate

18             classes according to cost of service practices to ensure overall consistent

19             treatment of these costs.




                                                                                         4
     Entergy Texas, Inc.                                                       Page 3 of 14
     Rebuttal Testimony of Heather G. LeBlanc
     Docket No. 39896


1    Q.     WHY SHOULD THESE COSTS BE ALLOCATED ACROSS ALL RETAIL

2           RATE CLASSES?

3    A.     Because these costs, regardless of their physical location, benefit all

4           customers within a given jurisdiction. Customers outside of a cities’ limits

5           benefit from the services (and streets and other facilities) provided within

6           the city limits because they invariably use those facilities when they travel

7           to the cities to use services (e.g., grocery stores, banks, shopping centers,

8           etc.) within the city limits.

9

10                                      B.      COS “Flaw”

11   Q.     MR. POLLOCK VAGUELY MENTIONS A THIRD “FLAW” IN A

12          FOOTNOTE ON PAGE 52 OF HIS TESTIMONY. DO YOU AGREE WITH

13          HIS ALLEGATION?

14   A.     No, and his testimony presents a confusing analysis on the issue. In that

15          footnote, Mr. Pollock states: “I am not addressing a third flaw: the failure to

16          classify any distribution network investment as customer-related.         The

17          reasons for doing so are discussed in Appendix C.” Mr. Pollock states

18          that he is not going to address the perceived “flaw,” but then continues by

19          adding a five page appendix to discuss this issue.            However, after

20          reviewing Appendix C, Mr. Pollock does indeed agree with the Company’s

21          classification of distribution costs. Mr. Pollock states: “Customer-related

22          costs vary directly with the number of customers and include expenses

23          such as meters, service drops, billing, and customer service” (pg 102,



                                                                                         5
     Entergy Texas, Inc.                                                       Page 4 of 14
     Rebuttal Testimony of Heather G. LeBlanc
     Docket No. 39896


1              lines 1-3, Appendix C). The Company has classified all of these costs as

2              customer-related.   There is no “flaw” in classifying distribution network

3              investment. The Company has produced a properly conducted class cost

4              of service study in accordance with industry accepted principles as well as

5              previous regulatory filings with the PUCT.

6

7                   C.    Updated Schedule P to include PPR in Base Rates

8    Q.        MR. CHRISS, ON BEHALF OF WAL-MART, STATES THAT THE

9              COMPANY’S SCHEDULE P REQUIRES UPDATING IN ORDER TO

10             COMPLY      WITH    THE      SUPPLEMENTAL       PRELIMINARY       ORDER

11             REGARDING THE PURCHASE POWER RIDER (PG 4).                        PLEASE

12             ADDRESS HIS CONTENTION.

13   A.        In response to Staff RFI 17-1, the Company presented a Summary of

14             Schedule P that includes the purchased capacity costs included in base

15             rates. I have attached that response and its attachments as my Exhibit

16             HGL-R-1.    ETI, therefore, has presented a summary that addresses

17             Mr. Chriss’ concerns.

18

19        D.       Allocation and Disallowance of Specific Project Codes or Accounts

20   Q.        DOES ANY WITNESS PROPOSE TO DIRECTLY ASSIGN SPECIFIC

21             COSTS TO SPECIFIC RATE CLASSES?

22   A.        Yes, OPUC witness Szerszen, at pages 44-45 of her direct testimony,

23             recommends that affiliate costs associated with larger industrial and



                                                                                         6
     Entergy Texas, Inc.                                                   Page 5 of 14
     Rebuttal Testimony of Heather G. LeBlanc
     Docket No. 39896


1           commercial sales, marketing, customer services, and other expenses

2           should be directly assigned to general service, large general service,

3           industrial and lighting classes.

4

5    Q.     DOES DR. SZERSZEN MAKE ANY OTHER RECOMMENDATIONS

6           CONCERNING SPECIFIC PROJECT CODES?

7    A.     Yes. On her pages 73 – 74, Dr. Szerszen claims that the retail customers

8           were inappropriately charged certain wholesale costs and these costs

9           should be disallowed.

10

11   Q.     WHAT IS THE COMPANY’S POSITION REGARDING DR. SZERSZEN’S

12          RECOMMENDATIONS OF DIRECTLY ASSIGNING AND DISALLOWING

13          THESE COSTS?

14   A.     These issues should be addressed together as they both pertain to the

15          same cost of service guidelines. The approach that Dr. Szerszen took is

16          often referred to as “cherry-picking” of costs. She has taken a limited

17          sample of costs and deemed them as being allocated inappropriately. An

18          approach such as Dr. Szerszen’s would be appropriate if an analysis of all

19          project codes was conducted to determine which individual projects

20          should be assigned to particular rate classes. However, to directly assign

21          a handful of costs is not feasible or appropriate.

22                  The cost of service study generally allocates costs at the FERC

23          account level. There are instances where project codes within an account



                                                                                     7
     Entergy Texas, Inc.                                                     Page 6 of 14
     Rebuttal Testimony of Heather G. LeBlanc
     Docket No. 39896


1           are looked at on an individual basis. One example is FERC account 928,

2           Regulatory Commission Expense.         The project codes charged to this

3           particular account can be clearly designated to specific functions and / or

4           rate classes. However, to do this detailed of an analysis on every FERC

5           account within the cost of service study would be more precise, but also

6           extremely tedious and manpower intensive, and would not guarantee a

7           reallocation away from the residential rate class, as appears to be

8           Dr. Szerszen’s objective. Moreover, there are numerous project codes

9           within each FERC account. There will be some project codes that are

10          clearly noted as Retail Only that will have portions allocated to the

11          Wholesale jurisdiction. For these reasons, the Company disagrees with

12          Dr. Szerszen’s cherry-picking approach to directly allocate or disallow

13          specific project codes.

14

15   Q.     STAFF WITNESS ABBOTT RECOMMENDS DIFFERENT ALLOCATION

16          FACTORS         FOR     408.152     FRANCHISE   TAX    STATE,      408.154

17          FRANCHISE TAX LOCAL, AND 408.163 – STREET RENTAL ON PAGE

18          22 OF HIS DIRECT TESTIMONY.               DO YOU AGREE WITH HIS

19          RECOMMENDATION?

20   A.     No, the Company believes that these FERC accounts are allocated

21          properly and in accordance with past filings made at the PUCT.




                                                                                       8
     Entergy Texas, Inc.                                                    Page 7 of 14
     Rebuttal Testimony of Heather G. LeBlanc
     Docket No. 39896


1                                  E.      Rebuttal COS Study

2    Q.     IS THE COMPANY FILING A REBUTTAL COST OF SERVICE?

3    A.     Yes. The Company is filing a Summary of Schedule P.

4

5    Q.     PLEASE EXPLAIN THE RESULTS OF THIS STUDY.

6    A.     The summary cost of service study presented in Exhibit-R-HGL-2

7           indicates that the annual retail base rate schedule revenue requirement,

8           excluding eligible fuel and purchase power expenses is $732 million. This

9           represents a $103.6 million retail revenue deficiency under the Company’s

10          currently effective rates, as shown on Exhibit-R-HGL-2, line 20, page 1.

11          But this revenue requirement does not include the Renewable Energy

12          Credit Rider. Including those expenses results in an overall retail revenue

13          deficiency of $104.8 million.

14

15   Q.     PLEASE LIST THE ADJUSTMENTS AND SPONSORING WITNESS FOR

16          EACH ADJUSTMENT MADE TO THE COST OF SERVICE FROM THE

17          FILED BASE CASE.

18   A.     The adjustments and their sponsoring witnesses are listed in Table 1

19          below.




                                                                                      9
     Entergy Texas, Inc.                                                      Page 8 of 14
     Rebuttal Testimony of Heather G. LeBlanc
     Docket No. 39896


1                                               Table 1

               Description                                Witness            Adjustment
                                                                               Number
     Rate Schedule Revenues             LeBlanc & Talkington                 AJ 1
     Rate Case Expense                  Severed per agreement with parties   AJ 11
     Depreciation Expense               Watson                               AJ 14
     Non-Affiliate Executive Perks      Accepting proposed adjustment        AJ 16E
     Affiliate Expense                  Tumminello                           AJ 21
     PPR Rider                          Cooper                               AJ 24
     Cash Working Capital               Joyce                                AJ 6
     Interest Synchronization           Considine                            AJ 17

            The incremental dollar amounts and line items affected are listed in
            Exhibit-HGL-R-3.


2    Q.     PLEASE EXPLAIN THE ADJUSTMENT YOU ARE CO-SPONSORING.

3    A.     In Adjustment 1, the Rate Schedule Revenues were adjusted to

4           $628,441,841 in order to include the Interruptible Service Credit of

5           $5,672,401 in Rate Schedule Revenues.

6

7                      III.    RENEWABLE ENERGY CREDIT RIDER

8    Q.     IS AN UPDATE TO THE COMPANY’S RENEWABLE ENERGY CREDIT

9           (“REC”) COSTS APPROPRIATE?

10   A.     Yes.      Intervenors and Staff have recommended changes to the

11          Company’s REC Rider proposal. If any changes are to be considered,

12          then updating the REC costs to reflect most current data available should

13          be considered as well.




                                                                                       10
     Entergy Texas, Inc.                                                      Page 9 of 14
     Rebuttal Testimony of Heather G. LeBlanc
     Docket No. 39896


1    Q.     PLEASE DISCUSS THE UPDATE YOU PROPOSE FOR THE REC

2           RIDER.

3    A.     Events following the Company’s initial filing in November 2011 caused the

4           costs associated with the renewable energy credits to increase.

5           Therefore, it is appropriate to update the REC Rider to the appropriate

6           level. The updated amount is $1,145,043. Applying the revenue-related

7           expense factor of 1.0137 yields an updated revenue requirement of

8           $1,160,008. This amount is then divided by all non-transmission level

9           kWh sales from RFP Schedule Q-7, as provided by Company witness

10          Talkington. The resulting rate is reflected in Attachment A of Exhibit HGL-

11          R-4.

12

13   Q.     GIVEN THE UPDATED AMOUNTS, SHOULD THESE COSTS STILL BE

14          RECOVERED THROUGH A RIDER MECHANISM?

15   A.     Yes. The updated amounts further support the Company’s position that

16          REC costs are volatile. In a little over four months since ETI filed this case

17          in November 2011, these costs have almost doubled.            Table 2 below

18          shows the annual REC costs that were incurred by or on behalf of ETI

19          over the past six years (RFI State 4-10, updated for 2011).




                                                                                       11
     Entergy Texas, Inc.                                                     Page 10 of 14
     Rebuttal Testimony of Heather G. LeBlanc
     Docket No. 39896


                                                Table 2

                                      Year          Amount

                               2006                          323,561

                               2007                          390,864

                               2008                          873,064

                               2009                          691,116

                               2010                          378,469

                               2011                       1,145,043



1           Table 2 proves the volatility of these costs. If in the current rate case, the

2           Company is ordered to move $1,160,008 associated with REC costs into

3           base rates, this could be detrimental to customers when compared to a

4           year such as 2010 when the costs were roughly one-fourth of the amount

5           that would be in base rates.

6

7    Q.     DO INTERVENOR AND STAFF WITNESSES RAISE SOME COMMON

8           OBJECTIONS TO ETI’S PROPOSED REC RIDER?

9    A.     Yes.     Intervenor witnesses Pevoto, Nalepa, and Benedict, and Staff

10          witness Abbott, all request that the REC Rider be denied because it

11          represents “piecemeal ratemaking.” I disagree with their positions and for

12          the reasons stated above and in my direct testimony, these costs are best

13          recovered through a rider. The costs in this rider are costs that ETI cannot

14          control – they are mandated through statute and the REC calculation



                                                                                       12
     Entergy Texas, Inc.                                                      Page 11 of 14
     Rebuttal Testimony of Heather G. LeBlanc
     Docket No. 39896


1           mechanism established by the PUCT.              Cities witness Brazell even

2           conceded in his deposition in this docket that these types of costs—costs

3           not within the control of the Company—are appropriate for recovery

4           through a rider mechanism.          See pages 79-80 of Mr. Brazell’s April 4

5           deposition in this docket.

6

7    Q.     ARE      THERE       ANY     OTHER      COMMONALITIES         AMONG       THE

8           WITNESSES?

9    A.     Yes. Both Staff witness Abbott (page 12) and State witness Pevoto (page

10          9) state that if the costs are moved into a rider, then there is a potential to

11          for “double counting” or “over recovery”.

12

13   Q.     WHAT IS YOUR OPINION ON “DOUBLE COUNTING” OR “OVER

14          RECOVERY”?

15   A.     I disagree that “double counting” or “over recovery” could potentially exist

16          if these costs are moved to a rider. I believe the greater risk for over

17          recovery is if these costs are kept in base rates. As shown in Table 2 on

18          page 10, years 2010 and 2011 are excellent examples of why these costs

19          should be moved into the REC Rider.




                                                                                        13
     Entergy Texas, Inc.                                                  Page 12 of 14
     Rebuttal Testimony of Heather G. LeBlanc
     Docket No. 39896


1    Q.     INTERVENOR WITNESS BENEDICT AT HIS PAGE 38 INDICATES

2           THAT THE USE OF RIDERS “REDUCES THE INCENTIVE OF THE

3           UTILITY TO CONSTRAIN COSTS.” DO YOU AGREE?

4    A.     No. Even with the proposed REC Rider, the Company is only allowed to

5           recover its reasonable and necessary costs. Accordingly, the Company

6           has and will continue to be incented to be mindful of the costs incurred

7           and is aware that these costs and any savings could be passed to

8           the customers.

9

10   Q.     ON PAGE 15 OF HIS TESTIMONY, MR. ABBOTT RECOMMENDS THAT THE

11          PREVIOUS YEAR’S ACTUAL REC COST SHOULD BE ALLOCATED TO EACH

12          CUSTOMER CLASS BASED UPON EACH CLASS’S ACTUAL ENERGY

13          USAGE OVER THE TIME PERIOD FOR WHICH THE RECS WERE

14          ACQUIRED. DO YOU HAVE ANY ISSUE WITH THIS RECOMMENDATION?

15   A.     I’m not sure exactly what is being recommended but I do not have an

16          issue with his recommendation if he means over the year in which the

17          obligation to purchase RECs is generated and not when they are actually

18          purchased to satisfy that obligation. Substantive rule 25.173 (d)(1) and

19          (h) shows that the obligation to procure RECs is based on the historical

20          usage during the compliance year so the energy use during that period

21          seems logical. The REC purchases typically are not ratable over the year

22          nor do they even have to be in the same year as the obligation is imposed

23          so that doesn’t seem to be the best allocation methodology.




                                                                                    14
     Entergy Texas, Inc.                                                      Page 13 of 14
     Rebuttal Testimony of Heather G. LeBlanc
     Docket No. 39896


1         IV.      TRANSMISSION COST RECOVERY FACTOR AND DISTRIBUTION
2                              COST RECOVERY FACTOR

3    Q.         INTERVENOR       WITNESS        CHRISS   (PAGE     7)   STATES       THAT

4               IMPLEMENTATION         OF       TCRF   AND    DCRF      WOULD       MOVE

5               APPROXIMATELY $238 MILLION OF ETI’S REVENUE REQUIREMENT

6               FROM BASE RATES TO EXACT RECOVER RIDERS. IS THIS A TRUE

7               STATEMENT?

8    A.         No, it is not.

9

10   Q.         PLEASE EXPLAIN THE INTENT OF THE COMPANY’S PROPOSAL

11              REGARDING THE TCRF AND DCRF.

12   A.         ETI is asking the Commission to establish in this docket the baseline

13              values that will be used to calculate ETI’s transmission cost recovery

14              factor and distribution cost recovery factor in future dockets.     This is

15              exactly the issue the Commission identified in its Supplemental

16              Preliminary Order as an issue to be addressed in this proceeding.

17

18   Q.         CITIES WITNESS BRAZELL AND STAFF WITNESS ABBOTT STATE

19              THAT IT WOULD BE REASONABLE TO DETERMINE THE BASELINE

20              VALUES DURING THE COMPLIANCE PHASE OF THIS HEARING.

21              WHAT IS THE COMPANY’S POSITION?

22   A.         ETI agrees that the baseline values can be established during the

23              compliance phase, however there are some concerns. Depending on the




                                                                                        15
    Entergy Texas, Inc.                                                    Page 14 of 14
    Rebuttal Testimony of Heather G. LeBlanc
    Docket No. 39896


1          nature of the final agreement this may or may not be possible. If there is

2          lack of specificity in the PFD or in a settlement, then there is not a clear

3          way to determine what costs will be adjusted to reach the settled revenue

4          requirement. To reach a true compliance cost of service, which is the

5          basis for these costs, a full list of adjustments would be needed.

6

7                                    V.        CONCLUSION

8   Q.     DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY?

9   A.     Yes.




                                                                                     16
                                                                                  Exhibit HGL-R-1
                                                                                 Docket No. 39896
                             ENTERGY TEXAS, INC.                                     Page 1 of 11
                     PUBLIC UTILITY COMMISSION OF TEXAS
                          SOAH DOCKET NO. XXX-XX-XXXX
                     PUC DOCKET NO. 39896 - 2011 ETI Rate Case

 Response of: Entergy Texas, Inc.                  Prepared By: Heather G. LeBlanc
 to the Seventeenth Set of Data Requests           Sponsoring Witness: Heather G. LeBlanc
 of Requesting Party: Commission Staff             Beginning Sequence No.
                                                   Ending Sequence No.

 Question No.: Staff 17-1                        Part No.:             Addendum:

 Question:

         By FERC account and subaccounts in the Schedule P format, please provide all
 costs included in the Company’s original request for a Purchased Power Recovery Rider
 which the Company is now seeking to be recovered through base rates. For each cost,
 also provide the Company’s requested allocation factor along with the allocated dollar
 amounts to each requested customer class.


 Response:

 This request has been modified be agreement between PUCT Staff and the Company.

 Please see the attached CD for the following files:

 Staff 17-1 - SCH_P_Summary_of_Results-2012-0320.xls
 Staff 17-1 - Alloc of Line Item Adjustments to include PPR.xlsx




                                                                                          17
39896                                                                Staff 17-1 BB1978
     Entergy Texas, Inc.                                                                                                                                          RFI Staff 17-1
     Rate Case                                                                                                                                                      Page 1 of 6
     Summary Model Results - Revenue Requirement Calculation
     ETICOS0611 - Analyst1_v2 - Electric
     For the Test Year Ended June 30, 2011


                                                                                                                    TOTAL
                                                                       LINE ITEM                                   COMPANY          TOTAL                      SMALL GEN
                                                                         NAME      PER BOOK         ADJMT          ADJUSTED         RETAIL         RES          SERVICE

           SUMMARY OF RESULTS

       1 RATE BASE                                                    RBTOA        1,279,186,389   457,511,540     1,736,697,930 1,714,972,039   986,918,408    54,907,193

         REVENUES
       2   RATE SCHEDULE REVENUE                                      RSRTOA       1,239,877,095   (591,857,546)    648,019,550    634,114,242   325,744,455    22,562,013
       3   OTHER SALES FOR RESALE                                     RSORTOA        314,299,128   (255,623,968)     58,675,159     55,966,597    27,841,011     1,231,592
       4 TOTAL SALES REVENUES (L2 + L3)                               RSTOA        1,554,176,223   (847,481,514)    706,694,709    690,080,839   353,585,466    23,793,605
       5 OTHER OPERATING REVENUES                                     ROTOA           33,511,398     14,660,594      48,171,991     47,809,873    25,549,679     1,268,006
       6 PROVISION FOR RATE REFUND                                    PROVRRTOA          672,315       (672,315)              0              0             0             0
       7 TOTAL REVENUES (L4 + L5 + L6)                                RTOA         1,588,359,936   (833,493,235)    754,866,701    737,890,713   379,135,145    25,061,611

       8 TOTAL OPERATING EXPENSES                                     OETOA        1,466,927,253   (787,915,619)    679,011,634    659,867,023   345,805,968    20,546,474

       9 TOTAL OPERATING INCOME (L7 - L8)                             OITOA         121,432,682     (45,577,616)     75,855,067     78,023,689    33,329,177     4,515,137

      10 EARNED RATE OF RETURN ON RATE BASE (L9 / L1)                 EROR                                                4.37%          4.55%         3.38%         8.22%

           REVENUE REQUIREMENT DETERMINATION

      11 REQUIRED RATE OF RETURN                                      ROR                                                 8.67%          8.67%         8.67%         8.67%
      12 REQUIRED OPERATING INCOME (L1 * L11)                         ROI                                           150,542,128
                                                                                                                    1 0 42 128     148,658,863
                                                                                                                                   148 6 8 863    85,549,015
                                                                                                                                                  8   49 01      4,759,518
                                                                                                                                                                 4   9 18

           REVENUE CONVERSION FACTORS
      13    INCOME TAX REVENUE CONVERSION FACTOR                      REVCOFIT                                           53.85%        53.85%        53.85%        53.85%
      14    REVENUE RELATED TAX REVENUE CONVERSION FACTOR             REVCOFRT                                            1.03%         1.03%         1.03%         1.03%
      15    REVCOFBD-BAD DEBT REVENUE CONVERSION FACTOR               REVCOFBD                                            0.41%         0.43%         0.53%         0.21%

           REVENUE DEFICIENCY
      16    OPERATING INCOME DEFICIENCY (L12 - L9)                    OIDEF                                          74,687,061     70,635,174    52,219,838      244,381
      17    INCREMENTAL INCOME TAX (L16 * L13)                        ITDEF                                          40,216,110     38,034,325    28,118,374      131,590
      18    INCREMENTAL REVENUE RELATED TAX (L16 + L17 + L19) * L14   RTDEF                                           1,186,860      1,122,736       830,874        3,876
      19    INCREMENTAL BAD DEBT EXPENSE (L16 + L17 + L18) * L15      BDDEF                                             474,506        474,506       433,118          805

      20 TOTAL REVENUE DEFICIENCY/(EXCESS) (SUM OF L16 - L19)         REVDEF                                        116,564,538    110,266,741    81,602,204      380,653
      21 % INCREASE/(DECREASE) (L20 / L2)                             REVDEFPCT                                          17.99%         17.39%        25.05%        1.69%

      22 RATE SCHEDULE REVENUE REQUIREMENT (L2 + L20)                 REVREQ                                        764,584,087    744,380,983   407,346,659    22,942,666




18
                                                                                                                                                                                       Page 2 of 11
                                                                                                                                                                                   Docket No. 39896
                                                                                                                                                                                    Exhibit HGL-R-1
     Entergy Texas, Inc.                                                                                                                                          RFI Staff 17-1
     Rate Case                                                                                                                                                      Page 2 of 6
     Summary Model Results - Revenue Requirement Calculation
     ETICOS0611 - Analyst1_v2 - Electric
     For the Test Year Ended June 30, 2011


                                                                                                                  LARGE
                                                                       LINE ITEM   GENERAL       LARGE GEN     INDUST PWR                    TOTAL
                                                                         NAME      SERVICE        SERVICE        SERVICE      LIGHTING     WHOLESALE WHOLESALE

           SUMMARY OF RESULTS

       1 RATE BASE                                                    RBTOA        354,952,484   119,866,792    178,557,355   19,769,808    21,725,890     21,725,890

         REVENUES
       2   RATE SCHEDULE REVENUE                                      RSRTOA       135,404,167    42,430,160    100,482,959    7,490,488    13,905,308     13,905,308
       3   OTHER SALES FOR RESALE                                     RSORTOA       10,576,726     4,153,849     11,993,261      170,158     2,708,563      2,708,563
       4 TOTAL SALES REVENUES (L2 + L3)                               RSTOA        145,980,893    46,584,009    112,476,220    7,660,646    16,613,870     16,613,870
       5 OTHER OPERATING REVENUES                                     ROTOA          9,722,781     3,587,550      7,401,304      280,553       362,118        362,118
       6 PROVISION FOR RATE REFUND                                    PROVRRTOA              0             0              0            0             0              0
       7 TOTAL REVENUES (L4 + L5 + L6)                                RTOA         155,703,673    50,171,559    119,877,524    7,941,199    16,975,988     16,975,988

       8 TOTAL OPERATING EXPENSES                                     OETOA        129,565,415    44,904,223    111,422,608    7,622,337    19,144,610     19,144,610

       9 TOTAL OPERATING INCOME (L7 - L8)                             OITOA         26,138,259     5,267,337      8,454,917      318,863     (2,168,622)   (2,168,622)

      10 EARNED RATE OF RETURN ON RATE BASE (L9 / L1)                 EROR               7.36%         4.39%          4.74%        1.61%         -9.98%        -9.98%

           REVENUE REQUIREMENT DETERMINATION

      11 REQUIRED RATE OF RETURN                                      ROR                8.67%         8.67%          8.67%        8.67%         8.67%          8.67%
      12 REQUIRED OPERATING INCOME (L1 * L11)                         ROI           30,768,334
                                                                                    30  68 334    10,390,409
                                                                                                  10 390 409     15,477,881
                                                                                                                 1  4 881      1,713,706
                                                                                                                               1  13 06      1,883,265
                                                                                                                                             1 883 26       1,883,265
                                                                                                                                                            1 883 26

           REVENUE CONVERSION FACTORS
      13    INCOME TAX REVENUE CONVERSION FACTOR                      REVCOFIT         53.85%        53.85%         53.85%        53.85%        53.85%        53.85%
      14    REVENUE RELATED TAX REVENUE CONVERSION FACTOR             REVCOFRT          1.03%         1.03%          1.03%         1.03%         1.03%         1.03%
      15    REVCOFBD-BAD DEBT REVENUE CONVERSION FACTOR               REVCOFBD          0.07%         0.02%          0.00%         1.59%         0.00%         0.00%

           REVENUE DEFICIENCY
      16    OPERATING INCOME DEFICIENCY (L12 - L9)                    OIDEF          4,630,076     5,123,072      7,022,964    1,394,843     4,051,887      4,051,887
      17    INCREMENTAL INCOME TAX (L16 * L13)                        ITDEF          2,493,118     2,758,577      3,781,596      751,069     2,181,785      2,181,785
      18    INCREMENTAL REVENUE RELATED TAX (L16 + L17 + L19) * L14   RTDEF             73,323        81,090        111,144       22,429        64,124         64,124
      19    INCREMENTAL BAD DEBT EXPENSE (L16 + L17 + L18) * L15      BDDEF              4,729         1,339              0       34,514             0              0

      20 TOTAL REVENUE DEFICIENCY/(EXCESS) (SUM OF L16 - L19)         REVDEF         7,201,246     7,964,079     10,915,704    2,202,856     6,297,796      6,297,796
      21 % INCREASE/(DECREASE) (L20 / L2)                             REVDEFPCT          5.32%        18.77%         10.86%       29.41%        45.29%         45.29%

      22 RATE SCHEDULE REVENUE REQUIREMENT (L2 + L20)                 REVREQ       142,605,413    50,394,239    111,398,663    9,693,344    20,203,104     20,203,104




19
                                                                                                                                                                                       Page 3 of 11
                                                                                                                                                                                   Docket No. 39896
                                                                                                                                                                                    Exhibit HGL-R-1
     Entergy Texas, Inc.                                                                                                                                   RFI Staff 17-1
     Rate Case                                                                                                                                               Page 3 of 6
     Summary Model Results - Rate Base
     ETICOS0611 - Analyst1_v2 - Electric
     For the Test Year Ended June 30, 2011


                                                                                                         TOTAL
                                                                                                        COMPANY                                          SMALL GEN
                                                       LINE ITEM NAME   PER BOOK        ADJMT           ADJUSTED         TOTAL RETAIL       RES           SERVICE

          RATE BASE SUMMARY

       1   PLANT IN SERVICE                            PLTOA          3,521,368,187    (251,512,491)    3,269,855,696     3,214,655,566 1,822,148,430      99,550,493
       2   ACCUMULATED DEPRECIATION / AMORTIZATION     ADTOA         (1,417,946,172)    148,061,290    (1,269,884,882)   (1,237,578,961) (671,739,109)    (35,984,479)
       3 NET PLANT                                     NPSUM          2,103,422,015    (103,451,201)    1,999,970,814     1,977,076,605 1,150,409,322      63,566,014
       4 WORKING CASH                                  WCTOA                      0      (6,412,426)       (6,412,426)       (6,333,831)   (3,644,842)       (202,781)
       5 FUEL INVENTORY                                FITOA             53,759,975               0        53,759,975        51,659,936    18,378,438       1,024,050
       6 MATERIALS AND SUPPLIES EXCLUDING ALLOWANCES   MSXATOA           29,252,574               0        29,252,574        28,757,611    16,235,399         870,236
       7 PREPAYMENTS                                   PPTOA              7,366,433        (148,396)        7,218,037         7,189,330     3,770,893         250,952
       8 PROPERTY INSURANCE RESERVE                    PIRTOA                     0      59,799,744        59,799,744        59,799,744    35,480,832       2,023,572
       9 INJURIES & DAMAGES RESERVES                   IDRTOA            (5,569,243)              0        (5,569,243)       (5,416,100)   (3,033,169)       (209,183)
      10 COAL CAR MAINTENANCE RESERVE                  CCMRTOA            1,400,350               0         1,400,350         1,345,648       478,725          26,675
      11 UNFUNDED PENSION                              PENTOA           (53,715,841)    109,689,386        55,973,545        54,434,394    30,484,797       2,102,391
      12 ALLOWANCES                                    AINTOA                68,914               0            68,914            67,750        38,403           2,098
      13 COMMERCIAL LITIGATION                         APCLTOA                    0               0                 0                 0             0               0
      14 ENVIRONMENTAL RESERVES                        ERTOA              3,412,379      (4,474,569)       (1,062,190)       (1,045,604)     (636,741)        (38,360)
      15 CUSTOMER DEPOSITS                             CDTOA            (35,872,476)              0       (35,872,476)      (35,872,476)  (20,615,725)     (1,147,023)
      16 ACCUMULATED DEFERRED INCOME TAXES             ADITTOA         (824,338,691)    369,967,144      (454,371,547)     (448,802,444) (258,266,098)    (14,368,648)
      17 ACCUMULATED DEFERRED ITC                      ADITCTOA                   0               0                 0                 0             0               0
      18 RATE CASE EXPENSES                            RCETOA                     0       6,175,000         6,175,000         6,175,000     3,172,097         219,709
      19 REGULATORY ASSETS AND LIABILITIES             REGASSLIABTOA              0      26,366,859        26,366,859        25,936,479    14,666,077         787,491
      20 RATE BASE                                     RBTOA          1,279,186,389     457,511,540     1,736,697,930     1,714,972,039   986,918,408      54,907,193




20
                                                                                                                                                                                Page 4 of 11
                                                                                                                                                                            Docket No. 39896
                                                                                                                                                                             Exhibit HGL-R-1
     Entergy Texas, Inc.                                                                                                                                   RFI Staff 17-1
     Rate Case                                                                                                                                               Page 4 of 6
     Summary Model Results - Rate Base
     ETICOS0611 - Analyst1_v2 - Electric
     For the Test Year Ended June 30, 2011


                                                                                                       LARGE
                                                                        GENERAL      LARGE GEN      INDUST PWR                       TOTAL
                                                       LINE ITEM NAME   SERVICE       SERVICE         SERVICE       LIGHTING       WHOLESALE WHOLESALE

          RATE BASE SUMMARY

       1   PLANT IN SERVICE                            PLTOA          654,061,437    224,673,016     377,286,581     36,935,609      55,200,130     55,200,130
       2   ACCUMULATED DEPRECIATION / AMORTIZATION     ADTOA         (243,142,466)   (87,152,791)   (184,605,312)   (14,954,805)    (32,305,921)   (32,305,921)
       3 NET PLANT                                     NPSUM          410,918,971    137,520,225     192,681,269     21,980,804      22,894,209     22,894,209
       4 WORKING CASH                                  WCTOA           (1,310,915)      (442,703)       (659,588)       (73,002)        (78,595)       (78,595)
       5 FUEL INVENTORY                                FITOA           10,698,216      4,957,497      16,347,084        254,651       2,100,040      2,100,040
       6 MATERIALS AND SUPPLIES EXCLUDING ALLOWANCES   MSXATOA          5,912,135      2,039,395       3,402,831        297,614         494,963        494,963
       7 PREPAYMENTS                                   PPTOA            1,509,688        481,613       1,085,699         90,485          28,708         28,708
       8 PROPERTY INSURANCE RESERVE                    PIRTOA          12,726,075      4,156,236       4,608,099        804,929               0              0
       9 INJURIES & DAMAGES RESERVES                   IDRTOA            (893,064)      (300,039)       (796,855)      (183,790)       (153,142)      (153,142)
      10 COAL CAR MAINTENANCE RESERVE                  CCMRTOA            278,669        129,134         425,812          6,633          54,702         54,702
      11 UNFUNDED PENSION                              PENTOA           8,975,716      3,015,531       8,008,777      1,847,182       1,539,151      1,539,151
      12 ALLOWANCES                                    AINTOA              13,785          4,735           7,951            778           1,163          1,163
      13 COMMERCIAL LITIGATION                         APCLTOA                  0              0               0              0               0              0
      14 ENVIRONMENTAL RESERVES                        ERTOA             (224,741)       (69,318)        (59,250)       (17,194)        (16,586)       (16,586)
      15 CUSTOMER DEPOSITS                             CDTOA           (7,420,226)    (2,508,469)     (3,770,974)      (410,059)              0              0
      16 ACCUMULATED DEFERRED INCOME TAXES             ADITTOA        (92,888,750)   (31,369,042)    (46,737,103)    (5,172,803)     (5,569,102)    (5,569,102)
      17 ACCUMULATED DEFERRED ITC                      ADITCTOA                 0              0               0              0               0              0
      18 RATE CASE EXPENSES                            RCETOA           1,318,565        413,185         978,502         72,942               0              0
      19 REGULATORY ASSETS AND LIABILITIES             REGASSLIABTOA    5,338,361      1,838,812       3,035,101        270,637         430,380        430,380
      20 RATE BASE                                     RBTOA          354,952,484    119,866,792     178,557,355     19,769,808      21,725,890     21,725,890




21
                                                                                                                                                                                Page 5 of 11
                                                                                                                                                                            Docket No. 39896
                                                                                                                                                                             Exhibit HGL-R-1
     Entergy Texas, Inc.                                                                                                                      RFI Staff 17-1
     Rate Case                                                                                                                                  Page 5 of 6
     Summary Model Results - Revenue/Expenses
     ETICOS0611 - Analyst1_v2 - Electric
     For the Test Year Ended June 30, 2011


                                                                                              TOTAL
                                                 LINE ITEM                                   COMPANY         TOTAL                      SMALL GEN
                                                   NAME      PER BOOK         ADJMT          ADJUSTED        RETAIL         RES          SERVICE

         REVENUES
       1 SALES REVENUES                         RSTOA        1,554,176,223   (847,481,514)    706,694,709   690,080,839   353,585,466    23,793,605
       2 OTHER OPERATING REVENUES               ROTOA           33,511,398     14,660,594      48,171,991    47,809,873    25,549,679     1,268,006
       3 PROVISION FOR RATE REFUND              PROVRRTOA          672,315       (672,315)              0             0             0             0
       4 TOTAL REVENUES                         RTOA         1,588,359,936   (833,493,235)    754,866,701   737,890,713   379,135,145    25,061,611

         OPERATING EXPENSES
          O & M EXPENSE
       5   PRODUCTION EXPENSES                  OMPTOA       1,125,799,286   (796,127,791)    329,671,495   314,874,032   153,643,756     6,884,606
       6   TRANSMISSION EXPENSES                OMTTOA          20,129,762      9,578,390      29,708,152    29,708,152    15,211,581       672,973
       7   REGIONAL MARKET EXPENSES




22
                                                                                                                                                                   Page 6 of 11
                                                                                                                                                               Docket No. 39896
                                                                                                                                                                Exhibit HGL-R-1
     Entergy Texas, Inc.                                                                                                                                           RFI Staff 17-1
     Rate Case                                                                                                                                                       Page 6 of 6
     Summary Model Results - Revenue/Expenses
     ETICOS0611 - Analyst1_v2 - Electric
     For the Test Year Ended June 30, 2011


                                                                                                           LARGE
                                                              LINE ITEM   GENERAL        LARGE GEN      INDUST PWR                      TOTAL
                                                                NAME      SERVICE         SERVICE         SERVICE       LIGHTING      WHOLESALE WHOLESALE

         REVENUES
       1 SALES REVENUES                                      RSTOA        145,980,893     46,584,009     112,476,220     7,660,646     16,613,870     16,613,870
       2 OTHER OPERATING REVENUES                            ROTOA          9,722,781      3,587,550       7,401,304       280,553        362,118        362,118
       3 PROVISION FOR RATE REFUND                           PROVRRTOA              0              0               0             0              0              0
       4 TOTAL REVENUES                                      RTOA         155,703,673     50,171,559     119,877,524     7,941,199     16,975,988     16,975,988

           OPERATING EXPENSES
            O & M EXPENSE
       5     PRODUCTION EXPENSES                             OMPTOA        59,917,175     23,846,510      69,583,655       998,330     14,797,463     14,797,463
       6     TRANSMISSION EXPENSES                           OMTTOA         5,779,533      2,269,972       5,681,126        92,967              0              0
       7     REGIONAL MARKET EXPENSES                        OMRTOTOA         809,392        317,898         726,182        13,020          3,424          3,424
       8     DISTRIBUTION EXPENSES                           OMDTOA         6,581,316      1,900,391         922,834     1,866,491        294,962        294,962
       9     CUSTOMER ACCOUNTING EXPENSES                    OMCATOA        1,120,648         91,700       1,186,772       225,254        761,839        761,839
      10     CUSTOMER SERVICES EXPENSES                      OMCSTOA          190,364          3,587         328,180        16,692              0              0
      11     SALES EXPENSES                                  OMSTOA           225,134         77,492         127,620        11,453         18,243         18,243
      12     ADMINISTRATIVE & GENERAL EXPENSES               OMAGTOA       13,465,718      4,614,565      11,648,151     2,246,027      2,177,391      2,177,391
      13    OPERATION & MAINTENANCE EXPENSE                  OMTOA         88,089,280     33,122,116      90,204,519     5,470,235     18,053,321     18,053,321
      14    GAINS FROM DISP OF ALLOWANCES                    GFDATOA                0              0               0             0              0              0
      15    REGULATORY DEBITS AND CREDITS                    RDCTOA           945,625        371,380       1,072,272        15,213        242,162        242,162
      16    INTEREST ON CUSTOMER DEPOSITS                    ICDTOA            14,270          4,824           7,252           789              0              0
      17    DEPRECIATION AND AMORTIZATION EXPENSE            DXTOA         19,448,711      6,373,998       9,904,303     1,299,833      1,531,353      1,531,353
      18    TAXES OTHER THAN INCOME                          TOTOA         12,628,896      4,159,983       8,441,856       804,987        638,529        638,529
            CURRENT INCOME TAXES
      19     FEDERAL INCOME TAX                              FTTOA          5,840,131        (18,333)         85,908      (234,027)     (1,719,958)   (1,719,958)
      20     STATE INCOME TAX                                STTOA             (6,051)        (2,033)         (5,399)       (1,245)         (1,038)       (1,038)
      21    CURRENT INCOME TAXES                             CITTOA         5,834,080        (20,366)         80,509      (235,272)     (1,720,995)   (1,720,995)
            PROVISION FOR DEFERRED INCOME TAXES
      22     PROVISION FOR DEFERRED INCOME TAXES - FEDERAL   DTFTOA         2,923,786      1,002,149       1,891,714       282,472        425,839        425,839
      23     PROVISION FOR DEFERRED INCOME TAXES - STATE     DTSTOA            13,526          4,544          12,068         2,784          2,319          2,319
      24    PROVISION FOR DEFERRED INCOME TAXES              DTTOA          2,937,312      1,006,693       1,903,783       285,256        428,159        428,159
      25    INVESTMENT TAX CREDITS A/C 411                   ITCTOA          (332,760)      (114,406)       (191,888)      (18,704)       (27,919)       (27,919)
      26   TOTAL OPERATING EXPENSES                          OETOA        129,565,415     44,904,223     111,422,608     7,622,337     19,144,610     19,144,610




23
                                                                                                                                                                                        Page 7 of 11
                                                                                                                                                                                    Docket No. 39896
                                                                                                                                                                                     Exhibit HGL-R-1
                                                                                             Exhibit HGL-R-1
                                                                                            Docket No. 39896
                                                                                                Page 8 of 11
Entergy Texas, Inc.
RFI Staff 17-1



Line Item Description                                Proformed Amount
OMP555IOD-555 INELIGIBLE - OTHER DEMAND (PG/DD/TO)          69,061,200    Exhibit RRC-1 (revised)
OMP555IOD-555 INELIGIBLE - OTHER DEMAND (PG/DD/NJ)           5,672,401    Interruptible Services (WP/P AJ 1.2)
                                                            74,733,601

OMP555IR-555 INELIGIBLE - RES EQUAL - PROD DEMAND           18,317,367    Exhibit RRC-1 (revised)

OMP555IRE-555 INELIGIBLE - RESOURCE PLAN                  188,430,917     Exhibit RRC-1 (revised)
OMP555ITOA-NON-RECOVERABLE                                281,481,885


Total Exhibit RRC-1 (revised)                             275,809,484
Total Interruptible Services (WP/P AJ 1.2)                  5,672,401
                                                          281,481,885



WCTO-WORKING CASH                                           (4,398,506)




                                                                                                      24
                                                                                                                                                                            RFI Staff 17-1
                                                                                                                                                                              Page 1 of 3

     CUBE:                                               cos_model:cos_line_item
     cos_model:test_case                                 ETICOS0611
     cos_model:version                                   Analyst1_v2
     cos_model:adjustment_name                           Total_All
     cos_model:books                                     balance
     cos_model:cos_line_item_m                           model_adjustments


                                                                                                                         TOTAL COMPANY                                   SMALL GEN
                                                                                                                                           TOTAL RETAIL     RES
                                                                                                                           ADJUSTED                                       SERVICE
     OMP555IOD-555 INELIGIBLE - OTHER DEMAND             PG-Production/Generation   DD-Demand   TO-Total All Customers        69,061,200       65,873,197   32,769,125      1,449,595
     OMP555IOD-555 INELIGIBLE - OTHER DEMAND             PG-Production/Generation   DD-Demand   NJ-Non-Jurisdictional          5,672,401        5,672,401    2,878,579        127,345
     OMP555IR-555 INELIGIBLE - RES EQUAL - PROD DEMAND   PG-Production/Generation   DD-Demand   TO-Total All Customers        18,317,367       17,471,801    8,691,481        384,482
     OMP555IRE-555 INELIGIBLE - RESOURCE PLAN            PG-Production/Generation   DD-Demand   TO-Total All Customers       188,430,917      179,732,569   89,409,340      3,955,165




25
                                                                                                                                                                                          Page 9 of 11
                                                                                                                                                                                      Docket No. 39896
                                                                                                                                                                                       Exhibit HGL-R-1
                                                                                                                                                                                 RFI Staff 17-1
                                                                                                                                                                                   Page 2 of 3

     CUBE:                                               cos_model:cos_line_item
     cos_model:test_case                                 ETICOS0611
     cos_model:version                                   Analyst1_v2
     cos_model:adjustment_name                           Total_All
     cos_model:books                                     balance
     cos_model:cos_line_item_m                           model_adjustments


                                                                                                                         GENERAL      LARGE GEN     LARGE INDUST
                                                                                                                                                                      LIGHTING
                                                                                                                         SERVICE       SERVICE      PWR SERVICE
     OMP555IOD-555 INELIGIBLE - OTHER DEMAND             PG-Production/Generation   DD-Demand   TO-Total All Customers   12,448,903     4,889,119       14,116,178       200,277
     OMP555IOD-555 INELIGIBLE - OTHER DEMAND             PG-Production/Generation   DD-Demand   NJ-Non-Jurisdictional     1,093,707       429,565         1,125,609       17,596
     OMP555IR-555 INELIGIBLE - RES EQUAL - PROD DEMAND   PG-Production/Generation   DD-Demand   TO-Total All Customers    3,301,870     1,296,760         3,744,088       53,120
     OMP555IRE-555 INELIGIBLE - RESOURCE PLAN            PG-Production/Generation   DD-Demand   TO-Total All Customers   33,966,369    13,339,778       38,515,468       546,450




26
                                                                                                                                                                                              Page 10 of 11
                                                                                                                                                                                           Docket No. 39896
                                                                                                                                                                                            Exhibit HGL-R-1
                                                                                                                                                       RFI Staff 17-1
                                                                                                                                                         Page 3 of 3

     CUBE:                                               cos_model:cos_line_item
     cos_model:test_case                                 ETICOS0611
     cos_model:version                                   Analyst1_v2
     cos_model:adjustment_name                           Total_All
     cos_model:books                                     balance
     cos_model:cos_line_item_m                           model_adjustments


                                                                                                                           TOTAL
                                                                                                                                         WHOLESALE
                                                                                                                         WHOLESALE
     OMP555IOD-555 INELIGIBLE - OTHER DEMAND             PG-Production/Generation   DD-Demand   TO-Total All Customers       3,188,003     3,188,003
     OMP555IOD-555 INELIGIBLE - OTHER DEMAND             PG-Production/Generation   DD-Demand   NJ-Non-Jurisdictional              -             -
     OMP555IR-555 INELIGIBLE - RES EQUAL - PROD DEMAND   PG-Production/Generation   DD-Demand   TO-Total All Customers         845,566       845,566
     OMP555IRE-555 INELIGIBLE - RESOURCE PLAN            PG-Production/Generation   DD-Demand   TO-Total All Customers       8,698,348     8,698,348




27
                                                                                                                                                                    Page 11 of 11
                                                                                                                                                                 Docket No. 39896
                                                                                                                                                                  Exhibit HGL-R-1
                                                                                                                                                                 Exhibit-HGL-R-2
                                                                                                                                                                     Page 1 of 6
     Entergy Texas, Inc.
     Rate Case
     Summary Model Results - Revenue Requirement Calculation
     ETICOS0611 - Rebuttal - Electric
     For the Test Year Ended June 30, 2011

     Exhibit-HGL-R-2
                                                                                                                    TOTAL
                                                                       LINE ITEM                                   COMPANY          TOTAL                      SMALL GEN
                                                                         NAME      PER BOOK         ADJMT          ADJUSTED         RETAIL         RES          SERVICE

           SUMMARY OF RESULTS

       1 RATE BASE                                                    RBTOA        1,279,186,389   456,696,198     1,735,882,587 1,714,106,482   986,717,865    54,862,854

         REVENUES
       2   RATE SCHEDULE REVENUE                                      RSRTOA       1,239,877,095   (597,529,947)    642,347,149    628,441,841   322,865,876    22,434,668
       3   OTHER SALES FOR RESALE                                     RSORTOA        314,299,128   (255,623,968)     58,675,159     55,966,597    27,841,011     1,231,592
       4 TOTAL SALES REVENUES (L2 + L3)                               RSTOA        1,554,176,223   (853,153,915)    701,022,308    684,408,438   350,706,887    23,666,260
       5 OTHER OPERATING REVENUES                                     ROTOA           33,511,398     14,660,594      48,171,991     47,809,873    25,549,995     1,268,671
       6 PROVISION FOR RATE REFUND                                    PROVRRTOA          672,315       (672,315)              0              0             0             0
       7 TOTAL REVENUES (L4 + L5 + L6)                                RTOA         1,588,359,936   (839,165,636)    749,194,300    732,218,312   376,256,882    24,934,931

       8 TOTAL OPERATING EXPENSES                                     OETOA        1,466,927,253   (797,912,908)    669,014,346    649,997,682   340,815,183    20,320,177

       9 TOTAL OPERATING INCOME (L7 - L8)                             OITOA         121,432,682     (41,252,728)     80,179,954     82,220,630    35,441,699     4,614,754

      10 EARNED RATE OF RETURN ON RATE BASE (L9 / L1)                 EROR                                                4.62%          4.80%         3.59%         8.41%

           REVENUE REQUIREMENT DETERMINATION

      11 REQUIRED RATE OF RETURN                                      ROR                                                 8.67%          8.67%         8.67%         8.67%
      12 REQUIRED OPERATING INCOME (L1 * L11)                         ROI                                           150,471,451    148,583,834    85,531,631     4,755,675

           REVENUE CONVERSION FACTORS
      13    INCOME TAX REVENUE CONVERSION FACTOR                      REVCOFIT                                           53.85%        53.85%        53.85%        53.85%
      14    REVENUE RELATED TAX REVENUE CONVERSION FACTOR             REVCOFRT                                            1.03%         1.03%         1.03%         1.03%
      15    REVCOFBD-BAD DEBT REVENUE CONVERSION FACTOR               REVCOFBD                                            0.42%         0.44%         0.53%         0.21%

           REVENUE DEFICIENCY
      16    OPERATING INCOME DEFICIENCY (L12 - L9)                    OIDEF                                          70,291,497     66,363,204    50,089,932      140,921
      17    INCREMENTAL INCOME TAX (L16 * L13)                        ITDEF                                          37,849,268     35,734,033    26,971,502       75,881
      18    INCREMENTAL REVENUE RELATED TAX (L16 + L17 + L19) * L14   RTDEF                                           1,117,092      1,054,924       796,985        2,235
      19    INCREMENTAL BAD DEBT EXPENSE (L16 + L17 + L18) * L15      BDDEF                                             454,560        454,560       415,453          464

      20 TOTAL REVENUE DEFICIENCY/(EXCESS) (SUM OF L16 - L19)         REVDEF                                        109,712,417    103,606,721    78,273,871      219,501
      21 % INCREASE/(DECREASE) (L20 / L2)                             REVDEFPCT                                          17.08%         16.49%        24.24%        0.98%

      22 RATE SCHEDULE REVENUE REQUIREMENT (L2 + L20)                 REVREQ                                        752,059,566    732,048,562   401,139,747    22,654,169

                                                                                                                                      1160008




28
                                                                                                                                                                                        Page 1 of 6
                                                                                                                                                                                   Docket No. 39896
                                                                                                                                                                                    Exhibit HGL-R-2
                                                                                                                                                                 Exhibit-HGL-R-2
                                                                                                                                                                     Page 2 of 6
     Entergy Texas, Inc.
     Rate Case
     Summary Model Results - Revenue Requirement Calculation
     ETICOS0611 - Rebuttal - Electric
     For the Test Year Ended June 30, 2011

     Exhibit-HGL-R-2
                                                                                                                  LARGE
                                                                       LINE ITEM   GENERAL       LARGE GEN     INDUST PWR                    TOTAL
                                                                         NAME      SERVICE        SERVICE        SERVICE      LIGHTING     WHOLESALE WHOLESALE

           SUMMARY OF RESULTS

       1 RATE BASE                                                    RBTOA        354,742,597   119,820,292    178,204,064   19,758,809    21,776,105     21,776,105

         REVENUES
       2   RATE SCHEDULE REVENUE                                      RSRTOA       134,310,460    42,000,595     99,357,350    7,472,892    13,905,308     13,905,308
       3   OTHER SALES FOR RESALE                                     RSORTOA       10,576,726     4,153,849     11,993,261      170,158     2,708,563      2,708,563
       4 TOTAL SALES REVENUES (L2 + L3)                               RSTOA        144,887,186    46,154,444    111,350,611    7,643,050    16,613,870     16,613,870
       5 OTHER OPERATING REVENUES                                     ROTOA          9,723,830     3,587,103      7,399,279      280,995       362,118        362,118
       6 PROVISION FOR RATE REFUND                                    PROVRRTOA              0             0              0            0             0              0
       7 TOTAL REVENUES (L4 + L5 + L6)                                RTOA         154,611,016    49,741,548    118,749,890    7,924,044    16,975,988     16,975,988

       8 TOTAL OPERATING EXPENSES                                     OETOA        127,638,111    44,146,730    109,511,019    7,566,462    19,016,664     19,016,664

       9 TOTAL OPERATING INCOME (L7 - L8)                             OITOA         26,972,905     5,594,818      9,238,871      357,583     (2,040,676)   (2,040,676)

      10 EARNED RATE OF RETURN ON RATE BASE (L9 / L1)                 EROR               7.60%         4.67%          5.18%        1.81%         -9.37%        -9.37%

           REVENUE REQUIREMENT DETERMINATION

      11 REQUIRED RATE OF RETURN                                      ROR                8.67%         8.67%          8.67%        8.67%         8.67%          8.67%
      12 REQUIRED OPERATING INCOME (L1 * L11)                         ROI           30,750,141    10,386,378     15,447,257    1,712,752     1,887,617      1,887,617

           REVENUE CONVERSION FACTORS
      13    INCOME TAX REVENUE CONVERSION FACTOR                      REVCOFIT         53.85%        53.85%         53.85%        53.85%        53.85%        53.85%
      14    REVENUE RELATED TAX REVENUE CONVERSION FACTOR             REVCOFRT          1.03%         1.03%          1.03%         1.03%         1.03%         1.03%
      15    REVCOFBD-BAD DEBT REVENUE CONVERSION FACTOR               REVCOFBD          0.07%         0.02%          0.00%         1.59%         0.00%         0.00%

           REVENUE DEFICIENCY
      16    OPERATING INCOME DEFICIENCY (L12 - L9)                    OIDEF          3,777,236     4,791,560      6,208,386    1,355,170     3,928,293      3,928,293
      17    INCREMENTAL INCOME TAX (L16 * L13)                        ITDEF          2,033,896     2,580,071      3,342,977      729,707     2,115,235      2,115,235
      18    INCREMENTAL REVENUE RELATED TAX (L16 + L17 + L19) * L14   RTDEF             59,817        75,843         98,252       21,792        62,168         62,168
      19    INCREMENTAL BAD DEBT EXPENSE (L16 + L17 + L18) * L15      BDDEF              3,858         1,253              0       33,532             0              0

      20 TOTAL REVENUE DEFICIENCY/(EXCESS) (SUM OF L16 - L19)         REVDEF         5,874,807     7,448,727      9,649,615    2,140,200     6,105,696      6,105,696
      21 % INCREASE/(DECREASE) (L20 / L2)                             REVDEFPCT          4.37%        17.73%          9.71%       28.64%        43.91%         43.91%

      22 RATE SCHEDULE REVENUE REQUIREMENT (L2 + L20)                 REVREQ       140,185,267    49,449,322    109,006,965    9,613,092    20,011,004     20,011,004




29
                                                                                                                                                                                        Page 2 of 6
                                                                                                                                                                                   Docket No. 39896
                                                                                                                                                                                    Exhibit HGL-R-2
                                                                                                                                                          Exhibit-HGL-R-2
                                                                                                                                                              Page 3 of 6


     Entergy Texas, Inc.
     Rate Case
     Summary Model Results - Rate Base
     ETICOS0611 - Rebuttal - Electric
     For the Test Year Ended June 30, 2011

     Exhibit-HGL-R-2
                                                                                                          TOTAL
                                                                                                         COMPANY                                         SMALL GEN
                                                       LINE ITEM NAME    PER BOOK          ADJMT         ADJUSTED        TOTAL RETAIL       RES           SERVICE

          RATE BASE SUMMARY

       1   PLANT IN SERVICE                            PLTOA             3,521,368,187    (251,512,491) 3,269,855,696     3,214,655,566 1,822,148,430      99,550,493
       2   ACCUMULATED DEPRECIATION / AMORTIZATION     ADTOA            (1,417,946,172)    148,061,290 (1,269,884,882)   (1,237,578,961) (671,739,109)    (35,984,479)
       3 NET PLANT                                     NPSUM             2,103,422,015    (103,451,201) 1,999,970,814     1,977,076,605 1,150,409,322      63,566,014
       4 WORKING CASH                                  WCTOA                         0      (3,214,019)    (3,214,019)       (3,174,516)   (1,827,345)       (101,603)
       5 FUEL INVENTORY                                FITOA                53,759,975               0     53,759,975        51,659,936    18,378,438       1,024,050
       6 MATERIALS AND SUPPLIES EXCLUDING ALLOWANCES   MSXATOA              29,252,574               0     29,252,574        28,757,611    16,235,399         870,236
       7 PREPAYMENTS                                   PPTOA                 7,366,433        (148,396)     7,218,037         7,189,330     3,771,213         251,627
       8 PROPERTY INSURANCE RESERVE                    PIRTOA                        0      59,799,744     59,799,744        59,799,744    35,480,832       2,023,572
       9 INJURIES & DAMAGES RESERVES                   IDRTOA               (5,569,243)              0     (5,569,243)       (5,416,100)   (3,033,169)       (209,183)
      10 COAL CAR MAINTENANCE RESERVE                  CCMRTOA               1,400,350               0      1,400,350         1,345,648       478,725          26,675
      11 UNFUNDED PENSION                              PENTOA              (53,715,841)    109,689,386     55,973,545        54,434,394    30,484,797       2,102,391
      12 ALLOWANCES                                    AINTOA                   68,914               0         68,914            67,750        38,403           2,098
      13 COMMERCIAL LITIGATION                         APCLTOA                       0               0              0                 0             0               0
      14 ENVIRONMENTAL RESERVES                        ERTOA                 3,412,379      (4,474,569)    (1,062,190)       (1,045,604)     (636,741)        (38,360)
      15 CUSTOMER DEPOSITS                             CDTOA               (35,872,476)              0    (35,872,476)      (35,872,476)  (20,621,797)     (1,146,675)
      16 ACCUMULATED DEFERRED INCOME TAXES             ADITTOA            (824,338,691)    372,128,394   (452,210,297)     (446,652,317) (257,106,288)    (14,295,478)
      17 ACCUMULATED DEFERRED ITC                      ADITCTOA                      0               0              0                 0             0               0
      18 RATE CASE EXPENSES                            RCETOA                        0               0              0                 0             0               0
      19 REGULATORY ASSETS AND LIABILITIES             REGASSLIABTOA                 0      26,366,859     26,366,859        25,936,479    14,666,077         787,491
      20 RATE BASE                                     RBTOA             1,279,186,389     456,696,198  1,735,882,587     1,714,106,482   986,717,865      54,862,854




30
                                                                                                                                                                                 Page 3 of 6
                                                                                                                                                                            Docket No. 39896
                                                                                                                                                                             Exhibit HGL-R-2
                                                                                                                                                             Exhibit-HGL-R-2
                                                                                                                                                                 Page 4 of 6


     Entergy Texas, Inc.
     Rate Case
     Summary Model Results - Rate Base
     ETICOS0611 - Rebuttal - Electric
     For the Test Year Ended June 30, 2011

     Exhibit-HGL-R-2
                                                                                                          LARGE
                                                                        GENERAL         LARGE GEN      INDUST PWR                       TOTAL
                                                       LINE ITEM NAME   SERVICE          SERVICE         SERVICE       LIGHTING       WHOLESALE WHOLESALE

          RATE BASE SUMMARY

       1   PLANT IN SERVICE                            PLTOA             654,061,437    224,673,016     377,286,581     36,935,609      55,200,130     55,200,130
       2   ACCUMULATED DEPRECIATION / AMORTIZATION     ADTOA            (243,142,466)   (87,152,791)   (184,605,312)   (14,954,805)    (32,305,921)   (32,305,921)
       3 NET PLANT                                     NPSUM             410,918,971    137,520,225     192,681,269     21,980,804      22,894,209     22,894,209
       4 WORKING CASH                                  WCTOA                (656,973)      (221,909)       (330,099)       (36,587)        (39,503)       (39,503)
       5 FUEL INVENTORY                                FITOA              10,698,216      4,957,497      16,347,084        254,651       2,100,040      2,100,040
       6 MATERIALS AND SUPPLIES EXCLUDING ALLOWANCES   MSXATOA             5,912,135      2,039,395       3,402,831        297,614         494,963        494,963
       7 PREPAYMENTS                                   PPTOA               1,510,752        481,160       1,083,646         90,933          28,708         28,708
       8 PROPERTY INSURANCE RESERVE                    PIRTOA             12,726,075      4,156,236       4,608,099        804,929               0              0
       9 INJURIES & DAMAGES RESERVES                   IDRTOA               (893,064)      (300,039)       (796,855)      (183,790)       (153,142)      (153,142)
      10 COAL CAR MAINTENANCE RESERVE                  CCMRTOA               278,669        129,134         425,812          6,633          54,702         54,702
      11 UNFUNDED PENSION                              PENTOA              8,975,716      3,015,531       8,008,777      1,847,182       1,539,151      1,539,151
      12 ALLOWANCES                                    AINTOA                 13,785          4,735           7,951            778           1,163          1,163
      13 COMMERCIAL LITIGATION                         APCLTOA                     0              0               0              0               0              0
      14 ENVIRONMENTAL RESERVES                        ERTOA                (224,741)       (69,318)        (59,250)       (17,194)        (16,586)       (16,586)
      15 CUSTOMER DEPOSITS                             CDTOA              (7,419,579)    (2,508,761)     (3,765,636)      (410,028)              0              0
      16 ACCUMULATED DEFERRED INCOME TAXES             ADITTOA           (92,435,726)   (31,222,407)    (46,444,666)    (5,147,752)     (5,557,980)    (5,557,980)
      17 ACCUMULATED DEFERRED ITC                      ADITCTOA                    0              0               0              0               0              0
      18 RATE CASE EXPENSES                            RCETOA                      0              0               0              0               0              0
      19 REGULATORY ASSETS AND LIABILITIES             REGASSLIABTOA       5,338,361      1,838,812       3,035,101        270,637         430,380        430,380
      20 RATE BASE                                     RBTOA             354,742,597    119,820,292     178,204,064     19,758,809      21,776,105     21,776,105




31
                                                                                                                                                                                    Page 4 of 6
                                                                                                                                                                               Docket No. 39896
                                                                                                                                                                                Exhibit HGL-R-2
                                                                                                                                                                Exhibit-HGL-R-2
                                                                                                                                                                    Page 5 of 6


     Entergy Texas, Inc.
     Rate Case
     Summary Model Results - Revenue/Expenses
     ETICOS0611 - Rebuttal - Electric
     For the Test Year Ended June 30, 2011

     Exhibit-HGL-R-2
                                                                                                           TOTAL
                                                             LINE ITEM                                    COMPANY         TOTAL                        SMALL GEN
                                                               NAME      PER BOOK          ADJMT          ADJUSTED        RETAIL          RES           SERVICE

         REVENUES
       1 SALES REVENUES                                      RSTOA     1,554,176,223      (853,153,915)   701,022,308    684,408,438    350,706,887     23,666,260
       2 OTHER OPERATING REVENUES                            ROTOA        33,511,398        14,660,594     48,171,991     47,809,873     25,549,995      1,268,671
       3 PROVISION FOR RATE REFUND                           PROVRRTOA       672,315          (672,315)             0              0              0              0
       4 TOTAL REVENUES                                      RTOA      1,588,359,936      (839,165,636)   749,194,300    732,218,312    376,256,882     24,934,931

           OPERATING EXPENSES
            O & M EXPENSE
       5     PRODUCTION EXPENSES                             OMPTOA   1,125,799,286       (801,800,192)   323,999,094    309,201,631    150,765,177      6,757,261
       6     TRANSMISSION EXPENSES                           OMTTOA      20,129,762          9,578,390     29,708,152     29,708,152     15,211,581        672,973
       7     REGIONAL MARKET EXPENSES                        OMRTOTOA        59,235          4,035,230      4,094,465      4,091,040      2,130,302         94,246
       8     DISTRIBUTION EXPENSES                           OMDTOA      30,897,632            100,452     30,998,085     30,703,123     18,100,956      1,331,134
       9     CUSTOMER ACCOUNTING EXPENSES                    OMCATOA     15,861,111          2,173,290     18,034,401     17,272,562     13,524,809      1,123,379
      10     CUSTOMER SERVICES EXPENSES                      OMCSTOA     13,419,093         (8,997,635)     4,421,457      4,421,457      3,574,589        308,046
      11     SALES EXPENSES                                  OMSTOA       1,097,967             13,865      1,111,832      1,093,589        618,643         33,247
      12     ADMINISTRATIVE & GENERAL EXPENSES               OMAGTOA     84,420,629         (8,417,345)    76,003,284     74,013,785     41,366,155      2,759,029
      13    OPERATION & MAINTENANCE EXPENSE                  OMTOA    1,291,684,715       (803,313,946)   488,370,769    470,505,340    245,292,212     13,079,314
      14    GAINS FROM DISP OF ALLOWANCES                    GFDATOA              0                  0              0              0              0              0
      15    REGULATORY DEBITS AND CREDITS                    RDCTOA      (6,784,608)        12,030,533      5,245,925      5,003,763      2,489,160        110,112
      16    INTEREST ON CUSTOMER DEPOSITS                    ICDTOA               0             68,985         68,985         68,985         39,657          2,205
      17    DEPRECIATION AND AMORTIZATION EXPENSE            DXTOA       76,072,458         20,173,155     96,245,613     94,722,100     55,345,207      3,320,046
      18    TAXES OTHER THAN INCOME                          TOTOA       63,023,906           (888,799)    62,135,106     61,496,577     33,403,296      2,062,259
            CURRENT INCOME TAXES
      19     FEDERAL INCOME TAX                              FTTOA         (23,407,031)    27,003,780       3,596,750      5,248,899     (2,847,271)     1,347,818
      20     STATE INCOME TAX                                STTOA            (127,519)        89,787         (37,732)       (36,694)       (20,550)        (1,417)
      21    CURRENT INCOME TAXES                             CITTOA        (23,534,549)    27,093,567       3,559,018      5,212,205     (2,867,821)     1,346,401
            PROVISION FOR DEFERRED INCOME TAXES
      22     PROVISION FOR DEFERRED INCOME TAXES - FEDERAL   DTFTOA         67,051,463     (52,089,274)    14,962,189     14,536,371      7,989,323        446,813
      23     PROVISION FOR DEFERRED INCOME TAXES - STATE     DTSTOA            812,265        (727,918)        84,347         82,027         45,938          3,168
      24    PROVISION FOR DEFERRED INCOME TAXES              DTTOA          67,863,727     (52,817,192)    15,046,536     14,618,399      8,035,261        449,981
      25    INVESTMENT TAX CREDITS A/C 411                   ITCTOA         (1,611,177)        (46,429)    (1,657,606)    (1,629,687)      (921,789)       (50,141)
      26   TOTAL OPERATING EXPENSES                          OETOA       1,466,927,253    (797,912,908)   669,014,346    649,997,682    340,815,183     20,320,177




32
                                                                                                                                                                                       Page 5 of 6
                                                                                                                                                                                  Docket No. 39896
                                                                                                                                                                                   Exhibit HGL-R-2
                                                                                                                                                                   Exhibit-HGL-R-2
                                                                                                                                                                       Page 6 of 6


     Entergy Texas, Inc.
     Rate Case
     Summary Model Results - Revenue/Expenses
     ETICOS0611 - Rebuttal - Electric
     For the Test Year Ended June 30, 2011

     Exhibit-HGL-R-2
                                                                                                          LARGE
                                                             LINE ITEM   GENERAL        LARGE GEN      INDUST PWR                      TOTAL
                                                               NAME      SERVICE         SERVICE         SERVICE       LIGHTING      WHOLESALE WHOLESALE

         REVENUES
       1 SALES REVENUES                                      RSTOA     144,887,186       46,154,444     111,350,611     7,643,050     16,613,870     16,613,870
       2 OTHER OPERATING REVENUES                            ROTOA       9,723,830        3,587,103       7,399,279       280,995        362,118        362,118
       3 PROVISION FOR RATE REFUND                           PROVRRTOA           0                0               0             0              0              0
       4 TOTAL REVENUES                                      RTOA      154,611,016       49,741,548     118,749,890     7,924,044     16,975,988     16,975,988

           OPERATING EXPENSES
            O & M EXPENSE
       5     PRODUCTION EXPENSES                             OMPTOA       58,823,468     23,416,945      68,458,046       980,734     14,797,463     14,797,463
       6     TRANSMISSION EXPENSES                           OMTTOA        5,779,533      2,269,972       5,681,126        92,967              0              0
       7     REGIONAL MARKET EXPENSES                        OMRTOTOA        809,392        317,898         726,182        13,020          3,424          3,424
       8     DISTRIBUTION EXPENSES                           OMDTOA        6,581,316      1,900,391         922,834     1,866,491        294,962        294,962
       9     CUSTOMER ACCOUNTING EXPENSES                    OMCATOA       1,120,648         91,700       1,186,772       225,254        761,839        761,839
      10     CUSTOMER SERVICES EXPENSES                      OMCSTOA         190,364          3,587         328,180        16,692              0              0
      11     SALES EXPENSES                                  OMSTOA          225,134         77,492         127,620        11,453         18,243         18,243
      12     ADMINISTRATIVE & GENERAL EXPENSES               OMAGTOA      12,679,346      4,293,876      10,688,480     2,226,899      1,989,498      1,989,498
      13    OPERATION & MAINTENANCE EXPENSE                  OMTOA        86,209,201     32,371,862      88,119,240     5,433,511     17,865,429     17,865,429
      14    GAINS FROM DISP OF ALLOWANCES                    GFDATOA               0              0               0             0              0              0
      15    REGULATORY DEBITS AND CREDITS                    RDCTOA          945,625        371,380       1,072,272        15,213        242,162        242,162
      16    INTEREST ON CUSTOMER DEPOSITS                    ICDTOA           14,268          4,825           7,242           789              0              0
      17    DEPRECIATION AND AMORTIZATION EXPENSE            DXTOA        18,944,585      6,193,527       9,658,846     1,259,888      1,523,513      1,523,513
      18    TAXES OTHER THAN INCOME                          TOTOA        12,633,927      4,157,843       8,432,152       807,101        638,529        638,529
            CURRENT INCOME TAXES
      19     FEDERAL INCOME TAX                              FTTOA         6,291,988       157,042         514,670       (215,348)     (1,652,149)   (1,652,149)
      20     STATE INCOME TAX                                STTOA            (6,051)       (2,033)         (5,399)        (1,245)         (1,038)       (1,038)
      21    CURRENT INCOME TAXES                             CITTOA        6,285,938       155,009         509,272       (216,593)     (1,653,187)   (1,653,187)
            PROVISION FOR DEFERRED INCOME TAXES
      22     PROVISION FOR DEFERRED INCOME TAXES - FEDERAL   DTFTOA        2,923,802      1,002,145       1,891,815       282,473        425,817        425,817
      23     PROVISION FOR DEFERRED INCOME TAXES - STATE     DTSTOA           13,526          4,544          12,068         2,784          2,319          2,319
      24    PROVISION FOR DEFERRED INCOME TAXES              DTTOA         2,937,328      1,006,689       1,903,884       285,256        428,137        428,137
      25    INVESTMENT TAX CREDITS A/C 411                   ITCTOA         (332,760)      (114,406)       (191,888)      (18,704)       (27,919)       (27,919)
      26   TOTAL OPERATING EXPENSES                          OETOA       127,638,111     44,146,730     109,511,019     7,566,462     19,016,664     19,016,664




33
                                                                                                                                                                                          Page 6 of 6
                                                                                                                                                                                     Docket No. 39896
                                                                                                                                                                                      Exhibit HGL-R-2
                                                                                                                                                              Exhibit-HGL-R3
     Entergy Texas, Inc.                                                                                                                                          Page 1 of 6
     Rate Case
     Model Adjustments - Incremental Change
     ETICOS0611 - Rebuttal - Electric
     For the Test Year Ended June 30, 2011
                                                                                           LeBlanc /         Severed Per                     Accepting
                                                                                                                               Watson                       Tumminello
                                                                                           Talkington        Agreement                      Proposed Adj
     Exhibit-HGL-R-3                                                                      Rate Schedule      Rate Case       Depreciation   Non-Affiliate
     Line                                                               Incremental         Revenues          Expense         Expense       Exec Perks       Affiliate
     No. Description                                                    Change Total           AJ01            AJ11             AJ14          AJ16E           AJ21
           Rate Base
           Working Cash
       1 WCTO-WORKING CASH                                                  (1,608,315)                 -             -               -              -               -
           ADIT - Federal
       2 ADFIT283-283 - FEDERAL                                              2,161,250                  -       2,161,250             -              -               -
           Rate Case Expense
       3 RCETO-182 RATE CASE EXPENSES                                       (6,175,000)                 -      (6,175,000)            -              -               -
       4 Total Rate Base                                                    (5,622,065)                 -      (4,013,750)            -              -               -

           Revenues
           Rate Schedule Revenues
       5   RSRRT-440-445 SALES-RETAIL                                       (5,672,401)        (5,672,401)            -               -              -               -


           Expenses
           O&M Expense
       6   OMP555IRE-555 INELIGIBLE - RESOURCE PLAN                        188,430,917                  -             -               -              -              -
       7   OMP555IR-555 INELIGIBLE - RES EQUAL - PROD DEMAND                18,317,367                  -             -               -              -              -
       8   OMP555IOD-555 INELIGIBLE - OTHER DEMAND                          69,061,200                  -             -               -              -              -
       9   OMAG923-923 OUTSIDE SERVICES                                        (52,827)                 -             -               -           (9,395)       (43,432)
      10   OMAG926-926 PENSIONS & BENEFITS                                    (112,531)                 -             -               -              -         (112,531)
      11   OMAG928PL-928 REGULATORY COMMISSION EXP - PRODUCTION LABOR       (4,116,667)                 -      (4,116,667)            -              -              -
      12   OMAG9302-930.2 MISC GENERAL EXPENSES                                   (929)                 -             -               -              -             (929)
      13   Total O&M Expense                                               271,526,530                  -      (4,116,667)            -           (9,395)      (156,892)




34
                                                                                                                                                                                 Page 1 of 6
                                                                                                                                                                            Docket No. 39896
                                                                                                                                                                             Exhibit HGL-R-3
                                                                                                                            Exhibit-HGL-R3
     Entergy Texas, Inc.                                                                                                        Page 2 of 6
     Rate Case
     Model Adjustments - Incremental Change
     ETICOS0611 - Rebuttal - Electric
     For the Test Year Ended June 30, 2011

                                                                         Cooper         Considine           Joyce

     Exhibit-HGL-R-3                                                                    AJ_INT -           AJ_WC -
     Line                                                               PPR Rider     Model Intr Sync   Model Work Cash
     No. Description                                                      AJ24            AJ 17               AJ 6
           Rate Base
           Working Cash
       1 WCTO-WORKING CASH                                                        -               -           (1,608,315)
           ADIT - Federal
       2 ADFIT283-283 - FEDERAL                                                   -               -                  -
           Rate Case Expense
       3 RCETO-182 RATE CASE EXPENSES                                             -               -                  -
       4 Total Rate Base                                                          -               -           (1,608,315)

           Revenues
           Rate Schedule Revenues
       5   RSRRT-440-445 SALES-RETAIL                                             -               -                  -


           Expenses
           O&M Expense
       6   OMP555IRE-555 INELIGIBLE - RESOURCE PLAN                     188,430,917               -                  -
       7   OMP555IR-555 INELIGIBLE - RES EQUAL - PROD DEMAND             18,317,367               -                  -
       8   OMP555IOD-555 INELIGIBLE - OTHER DEMAND                       69,061,200               -                  -
       9   OMAG923-923 OUTSIDE SERVICES                                         -                 -                  -
      10   OMAG926-926 PENSIONS & BENEFITS                                      -                 -                  -
      11   OMAG928PL-928 REGULATORY COMMISSION EXP - PRODUCTION LABOR           -                 -                  -
      12   OMAG9302-930.2 MISC GENERAL EXPENSES                                 -                 -                  -
      13   Total O&M Expense                                            275,809,484               -                  -




35
                                                                                                                                               Page 2 of 6
                                                                                                                                          Docket No. 39896
                                                                                                                                           Exhibit HGL-R-3
                                                                                                                                                          Exhibit-HGL-R3
     Entergy Texas, Inc.                                                                                                                                      Page 3 of 6
     Rate Case
     Model Adjustments - Incremental Change
     ETICOS0611 - Rebuttal - Electric
     For the Test Year Ended June 30, 2011
                                                                                         LeBlanc /        Severed Per                    Accepting
                                                                                                                          Watson                        Tumminello
                                                                                         Talkington       Agreement                     Proposed Adj
     Exhibit-HGL-R-3                                                                    Rate Schedule     Rate Case     Depreciation    Non-Affiliate
     Line                                                             Incremental         Revenues         Expense       Expense        Exec Perks       Affiliate
     No. Description                                                  Change Total           AJ01           AJ11           AJ14           AJ16E           AJ21
           Depreciation Expense
        1 DXT3502-350.2 LAND EASEMENTS                                        (8,495)                 -           -           (8,495)            -               -
        2 DXT352-352 STRUCTURES & IMPROVEMENTS                                (5,964)                 -           -           (5,964)            -               -
        3 DXT352C-352 STRUCTURES & IMPROVEMENTS - CONTRA                          71                  -           -               71             -               -
        4 DXT353-353 STATION EQUIPMENT                                      (157,972)                 -           -         (157,972)            -               -
        5 DXT353C-353 STATION EQUIPMENT - CONTRA                                 950                  -           -              950             -               -
        6 DXT354-354 TOWERS & FIXTURES                                       (51,700)                 -           -          (51,700)            -               -
        7 DXT354C-354 TOWERS & FIXTURES - CONTRA                               1,614                  -           -            1,614             -               -
        8 DXT355-355 POLES & FIXTURES                                       (913,008)                 -           -         (913,008)            -               -
        9 DXT355C-355 POLES & FIXTURES - CONTRA                              126,118                  -           -          126,118             -               -
       10 DXT356-356 OVERHEAD CONDUCTORS & DEVICES                          (367,597)                 -           -         (367,597)            -               -
       11 DXT356C-356 OVERHEAD CONDUCTORS & DEVICES - CONTRA                  31,481                  -           -           31,481             -               -
       12 DXT358-358 UNDERGROUND CONDUCTORS & DEVICES                            (37)                 -           -              (37)            -               -
       13 DXT359-359 ROADS & TRAILS                                             (128)                 -           -             (128)            -               -
       14 DXD3602-360.2 LAND RIGHTS                                           (1,494)                 -           -           (1,494)            -               -
       15 DXD361-361 STRUCTURES & IMPROVEMENTS                                  (727)                 -           -             (727)            -               -
       16 DXD362-362 STATION EQUIPMENT                                       (16,046)                 -           -          (16,046)            -               -
       17 DXD362C-362 STATION EQUIPMENT - CONTRA                                 289                  -           -              289             -               -
       18 DXD364-364 POLES, TOWERS, & FIXTURES                              (435,736)                 -           -         (435,736)            -               -
       19 DXD364C-364 POLES, TOWERS, & FIXTURES - CONTRA                      64,561                  -           -           64,561             -               -
       20 DXD365-365 OVERHEAD CONDUCTORS & DEVICES                          (454,879)                 -           -         (454,879)            -               -
       21 DXD365C-365 OVRHD CONDUCTORS & DEVICES - CONTRA                     63,902                  -           -           63,902             -               -
       22 DXD366-366 UNDERGROUND CONDUIT                                      (4,958)                 -           -           (4,958)            -               -
       23 DXD366C-366 UNDERGROUND CONDUIT - CONTRA                             2,066                  -           -            2,066             -               -
       24 DXD367-367 UNDG CONDUCT & DEVICES                                 (188,049)                 -           -         (188,049)            -               -
       25 DXD367C-367 UNDG CONDUCT & DEVICES - CONTRA                         43,534                  -           -           43,534             -               -
       26 DXD368-368 LINE TRANSFORMERS                                       (48,370)                 -           -          (48,370)            -               -
       27 DXD368C-368 LINE TRANSFORMERS - CONTRA                               5,167                  -           -            5,167             -               -
       28 DXD3691-369.1 OVERHEAD SERVICES                                    (23,571)                 -           -          (23,571)            -               -
       29 DXD3691C-369.1 OVERHEAD SERVICES - CONTRA                            6,322                  -           -            6,322             -               -
       30 DXD3692-369.2 UNDERGROUND SERVICES                                  (5,940)                 -           -           (5,940)            -               -
       31 DXD3692C-369.2 UNDERGROUND SERVICES - CONTRA                         2,056                  -           -            2,056             -               -
       32 DXD370-370 METERS                                                  (33,119)                 -           -          (33,119)            -               -
       33 DXD370C-370 METERS - CONTRA                                         13,784                  -           -           13,784             -               -
       34 DXD371L-371 INSTALL ON CUST PREMISES - LIGHTING                     (9,824)                 -           -           (9,824)            -               -
       35 DXD371LC-371 INSTALL ON CUST PREMISES - LIGHTING - CONTRA            3,994                  -           -            3,994             -               -
       36 DXD371O-371 INSTALL ON CUST PREMISES - OTHER                        (1,539)                 -           -           (1,539)            -               -
       37 DXD371OC-371 INSTALL ON CUST PREMISES - OTHER - CONTRA                 626                  -           -              626             -               -
       38 DXD373NR-373 ST LIGHT & SIGNAL SYS - NON RDWAY                          (3)                 -           -               (3)            -               -
       39 DXD373NRC-373 ST LIGHT & SIGNAL SYS - NON RDWAY - CONTRA                 7                  -           -                7             -               -




36
       40 DXD373R-373 ST LIGHT & SIGNAL SYS - ROADWAY                       (145,748)                 -           -         (145,748)            -               -
       41 DXD373RC-373 ST LIGHT & SIGNAL SYS - ROADWAY - CONTRA              122,818                  -           -          122,818             -               -
       42 Total Depreciation Expense                                      (2,385,544)                 -           -       (2,385,544)            -               -
                                                                                                                                                                             Page 3 of 6
                                                                                                                                                                        Docket No. 39896
                                                                                                                                                                         Exhibit HGL-R-3
                                                                                                                        Exhibit-HGL-R3
     Entergy Texas, Inc.                                                                                                    Page 4 of 6
     Rate Case
     Model Adjustments - Incremental Change
     ETICOS0611 - Rebuttal - Electric
     For the Test Year Ended June 30, 2011

                                                                       Cooper         Considine           Joyce

     Exhibit-HGL-R-3                                                                  AJ_INT -           AJ_WC -
     Line                                                             PPR Rider     Model Intr Sync   Model Work Cash
     No. Description                                                    AJ24            AJ 17               AJ 6
           Depreciation Expense
        1 DXT3502-350.2 LAND EASEMENTS                                          -               -                 -
        2 DXT352-352 STRUCTURES & IMPROVEMENTS                                  -               -                 -
        3 DXT352C-352 STRUCTURES & IMPROVEMENTS - CONTRA                        -               -                 -
        4 DXT353-353 STATION EQUIPMENT                                          -               -                 -
        5 DXT353C-353 STATION EQUIPMENT - CONTRA                                -               -                 -
        6 DXT354-354 TOWERS & FIXTURES                                          -               -                 -
        7 DXT354C-354 TOWERS & FIXTURES - CONTRA                                -               -                 -
        8 DXT355-355 POLES & FIXTURES                                           -               -                 -
        9 DXT355C-355 POLES & FIXTURES - CONTRA                                 -               -                 -
       10 DXT356-356 OVERHEAD CONDUCTORS & DEVICES                              -               -                 -
       11 DXT356C-356 OVERHEAD CONDUCTORS & DEVICES - CONTRA                    -               -                 -
       12 DXT358-358 UNDERGROUND CONDUCTORS & DEVICES                           -               -                 -
       13 DXT359-359 ROADS & TRAILS                                             -               -                 -
       14 DXD3602-360.2 LAND RIGHTS                                             -               -                 -
       15 DXD361-361 STRUCTURES & IMPROVEMENTS                                  -               -                 -
       16 DXD362-362 STATION EQUIPMENT                                          -               -                 -
       17 DXD362C-362 STATION EQUIPMENT - CONTRA                                -               -                 -
       18 DXD364-364 POLES, TOWERS, & FIXTURES                                  -               -                 -
       19 DXD364C-364 POLES, TOWERS, & FIXTURES - CONTRA                        -               -                 -
       20 DXD365-365 OVERHEAD CONDUCTORS & DEVICES                              -               -                 -
       21 DXD365C-365 OVRHD CONDUCTORS & DEVICES - CONTRA                       -               -                 -
       22 DXD366-366 UNDERGROUND CONDUIT                                        -               -                 -
       23 DXD366C-366 UNDERGROUND CONDUIT - CONTRA                              -               -                 -
       24 DXD367-367 UNDG CONDUCT & DEVICES                                     -               -                 -
       25 DXD367C-367 UNDG CONDUCT & DEVICES - CONTRA                           -               -                 -
       26 DXD368-368 LINE TRANSFORMERS                                          -               -                 -
       27 DXD368C-368 LINE TRANSFORMERS - CONTRA                                -               -                 -
       28 DXD3691-369.1 OVERHEAD SERVICES                                       -               -                 -
       29 DXD3691C-369.1 OVERHEAD SERVICES - CONTRA                             -               -                 -
       30 DXD3692-369.2 UNDERGROUND SERVICES                                    -               -                 -
       31 DXD3692C-369.2 UNDERGROUND SERVICES - CONTRA                          -               -                 -
       32 DXD370-370 METERS                                                     -               -                 -
       33 DXD370C-370 METERS - CONTRA                                           -               -                 -
       34 DXD371L-371 INSTALL ON CUST PREMISES - LIGHTING                       -               -                 -
       35 DXD371LC-371 INSTALL ON CUST PREMISES - LIGHTING - CONTRA             -               -                 -
       36 DXD371O-371 INSTALL ON CUST PREMISES - OTHER                          -               -                 -
       37 DXD371OC-371 INSTALL ON CUST PREMISES - OTHER - CONTRA                -               -                 -
       38 DXD373NR-373 ST LIGHT & SIGNAL SYS - NON RDWAY                        -               -                 -
       39 DXD373NRC-373 ST LIGHT & SIGNAL SYS - NON RDWAY - CONTRA              -               -                 -




37
       40 DXD373R-373 ST LIGHT & SIGNAL SYS - ROADWAY                           -               -                 -
       41 DXD373RC-373 ST LIGHT & SIGNAL SYS - ROADWAY - CONTRA                 -               -                 -
       42 Total Depreciation Expense                                            -               -                 -
                                                                                                                                           Page 4 of 6
                                                                                                                                      Docket No. 39896
                                                                                                                                       Exhibit HGL-R-3
                                                                                                                                    Exhibit-HGL-R3
     Entergy Texas, Inc.                                                                                                                Page 5 of 6
     Rate Case
     Model Adjustments - Incremental Change
     ETICOS0611 - Rebuttal - Electric
     For the Test Year Ended June 30, 2011
                                                                 LeBlanc /        Severed Per                      Accepting
                                                                                                    Watson                        Tumminello
                                                                 Talkington       Agreement                       Proposed Adj
     Exhibit-HGL-R-3                                            Rate Schedule     Rate Case       Depreciation    Non-Affiliate
     Line                                      Incremental        Revenues         Expense         Expense        Exec Perks       Affiliate
     No. Description                           Change Total          AJ01           AJ11             AJ14           AJ16E           AJ21
           Current Tax - Schedule M
       1 INTRADJ-INTEREST EXPENSE ADJUSTMENT         189,845                  -            -               -               -               -

       2   Total Expense                          269,330,831                 -     (4,116,667)     (2,385,544)         (9,395)      (156,892)




38
                                                                                                                                                       Page 5 of 6
                                                                                                                                                  Docket No. 39896
                                                                                                                                                   Exhibit HGL-R-3
                                                                                                 Exhibit-HGL-R3
     Entergy Texas, Inc.                                                                             Page 6 of 6
     Rate Case
     Model Adjustments - Incremental Change
     ETICOS0611 - Rebuttal - Electric
     For the Test Year Ended June 30, 2011

                                                Cooper         Considine           Joyce

     Exhibit-HGL-R-3                                           AJ_INT -           AJ_WC -
     Line                                      PPR Rider     Model Intr Sync   Model Work Cash
     No. Description                             AJ24            AJ 17               AJ 6
           Current Tax - Schedule M
       1 INTRADJ-INTEREST EXPENSE ADJUSTMENT             -          189,845                -

       2   Total Expense                       275,809,484          189,845                -




39
                                                                                                                    Page 6 of 6
                                                                                                               Docket No. 39896
                                                                                                                Exhibit HGL-R-3
                                                                                                          Exhibit HGL-R-4
                                                                                                        Docket No. 39896
                                                                                                              Page 1 of 5
                                                                                                    Page 45.1
 SECTION III RATE SCHEDULE

         ENTERGY TEXAS, INC.                      Sheet No.: 110
               Electric Service                   Effective Date: Proposed
                                                  Revision: 0
                                                  Supersedes: New Schedule
              SCHEDULE REC                        Schedule Consists of: One Sheet Plus
                                                                        Attachments A and B


                                  RENEWABLE ENERGY CREDIT RIDER


I.     PURPOSE

       This Renewable Energy Credit Rider (“Rider REC”) defines the procedure by which Entergy
       Texas, Inc. (“ETI” or “Company”) shall implement and adjust rates for recovery of renewable
       energy credit costs.

II.    APPLICABILITY

       This rider is applicable to electric service provided by the Company to all customers served under
       applicable retail rate schedules set forth in Attachment A to this Rider REC, whether metered or
       unmetered, subject to the jurisdiction of the Public Utility Commission of Texas (“PUCT”).

III.   RENEWABLE ENERGY CREDIT RATE

       The rate associated with Rider REC (“Renewable Energy Credit Rate”) shall be as set forth in
       Attachment A by application of the formula set out in Attachment B to this Rider REC
       (“Renewable Energy Credit Rider Rate Development Formula”).
                                                                                                                   N
       The initial Renewable Energy Credit Rate shall be based on the renewable energy credit costs
       that the Company expects to incur on a Texas Retail basis for the twelve (12) months ending May
       31, 2013. The initial Renewable Energy Credit Rate shall become effective with the first billing
       cycle of the month following the date of the PUCT order approving this Rider REC if such order is
       received by the fifth (5th) day of the month, otherwise, the initial Renewable Energy Credit Rate
       shall become effective with the first (1st) billing cycle of the second subsequent month after the
       date of the PUCT order approving this Rider REC and shall remain in effect until superseded.

       On or before May 1, beginning in 2013, the Company shall file a redetermination of the
       Renewable Energy Credit Rate, as set out in Attachment A by application of the formula set out in
       Attachment B to this Rider REC together with a set of workpapers sufficient to document fully the
       calculation of the redetermined Renewable Energy Credit Rate. The redetermined Renewable
       Energy Credit Rate shall be based on the Renewable Energy Credit Costs that the Company
       expects to incur on a Texas Retail basis during the twelve (12) months beginning June 1
       immediately following the applicable May filing and a true-up adjustment reflecting the Rider REC
       (Over) / Under Recovery Balance. The Renewable Energy Credit Rate so determined shall be
       effective for bills rendered on and after the first (1st) billing cycle of July immediately following the
       May filing and shall remain in effect until superseded.




                                        (Continued on reverse side)

                                                                                                             40
                                                                                                 Exhibit HGL-R-4
                                                                                               Docket No. 39896
                                                                                                     Page 2 of 5
                                                                                           Page 45.2


      For the initial redetermination, the true-up adjustment shall reflect the Cumulative Rider REC
      (Over)/Under Recovery balance for the period which shall commence on the date that the
      Renewable Energy Credit Rate is approved and becomes effective and shall end December 31,
      2012. For each subsequent redetermination beginning in 2014, the true-up period shall be the
      twelve-month billing period ended December of the prior calendar year.

      Interest shall be calculated monthly on the Cumulative Rider REC (Over)/Under Recovery
      Balance at the interest rate established annually by the PUCT for overbilling and certain
      underbilling under P.U.C. SUBST. R. 25.28(c) and (d). Interest cost shall be calculated based on
      the principles set out in P.U.C. SUBST. R. 25.236(e)(1).                                            N

IV.   TERM

      This Rider REC shall remain in effect until modified and will terminate upon the introduction of
      customer choice. If this Rider REC is terminated by a future order of the PUCT, the Renewable
      Energy Credit Rate shall continue to be in effect until such costs are recovered through another
      mechanism or until new base rates reflecting the Renewable Energy Credit Costs are duly
      approved and implemented.




SCHEDULE REC

                                                                                                   41
                                                                                                   Exhibit HGL-R-4
                                                                                                 Docket No. 39896
                                                                                         Page 45.3     Page 3 of 5



                                                                                     Attachment A

                                     ENTERGY TEXAS, INC.
                             RENEWABLE ENERGY CREDIT RATE
                                     RIDER SCHEDULE REC




Net Monthly Rate                                                                                                N

The following Rate Adjustment will be added to the rates set out in the Net Monthly Bill for electric service
billed under applicable retail rate schedules* on file with the Public Utility Commission of Texas (“PUCT”).
The Rate Adjustment shall be effective for bills rendered on and after the first billing cycle of June 2012
and shall remain in effect through the May 2013 Billing Month. Amounts billed pursuant to this Rider REC
are subject to State and local sales taxes.


Rate Adjustment:                         $0.000108 / kWh


*Excluded Schedules: EAPS, SMS and customers receiving service at transmission-level voltage that
 submit an opt-out notice to the PUCT and otherwise comply with the requirements of P.U.C. SUBST. R.
 25.173(j).




                                                                                                      42
                                                                                                      Exhibit HGL-R-4
                                                                                                    Docket No. 39896
                                                                                                Page 45.4 Page 4 of 5

                                                                                            Attachment B
                                                                                               Page 1 of 2
                                          ENTERGY TEXAS, INC.
                                 RENEWABLE ENERGY CREDIT RIDER
                                    RATE DEVELOPMENT FORMULA

    Ln                                     Description                                    Amount ($)
    No.
     1    Texas Retail Renewable Energy Credit Costs (1)                                     $1,145,043
    2     Cumulative Rider REC (Over) / Under Recovery Balance (2)                             $       0
          Total Renewable Energy Credit Costs Before Revenue Related Expenses
    3     (Ln 1 + Ln 2)                                                                      $1,145,043
    4     Revenue Related Expense Factor (3)                                                    1.01307
    5     Total Texas Retail Revenue Requirement (Ln 3 * Ln 4)                               $1,160,008
    6      All Non-Transmission Sales (kWh) (4)                                          10,745,512,000
    7     Renewable Energy Credit Rate (Ln 5 / Ln 6) ($/kWh)                           $0.000108 / kWh

Notes:
 (1) For the initial filing, Renewable Energy Credit Costs are to be based on the costs that the Company
     projects to incur during the twelve (12) months ending June 30, 2011. For subsequent
     redeterminations, Renewable Energy Credit Costs are to be based on Renewable Energy Credit               N
     Costs that the Company expects to incur on a Texas Retail basis during the twelve (12) months
     beginning June 1 immediately following the applicable May filing.
 (2) Attachment B, page 2, line 6
 (3) Revenue Related Expense Factor = 1 / ((1-Texas Retail Bad Debt Rate) * (1-Texas Retail Revenue
     Related Tax Rate)). For the initial filing, the Revenue Related Expense Factor = 1/((1-0.2723% -
     1.0182%) = 1.01307 where, Texas Retail Bad Debt Rate of 0.2723% is per WP/P MD 1.1, line 1, and
     Texas Retail Revenue Related Tax Rate of 1.0182% is per WP/P MD 1.1, line 3, in the RFP filed in
     the 2011 Rate Case. For subsequent redeterminations, the Texas Retail Bad Debt Rate and the
     Texas Retail Revenue Related Tax Rate shall be developed consistent with the methodology utilized
     for calculating them in the 2011 Rate Case and shall be based on the most recently available
     calendar year data at the time of filing.
 (4) For the initial filing, Retail Billing Determinants (kWh) are based on data for the twelve (12) months
     ended June 30, 2011. See RFP Schedule Q-7, pages 1-11, filed in the 2011 Rate Case. For
     subsequent redetermination, the Retail Billing Determinants shall be based on data for the twelve (12)
     months ended December 31 immediately preceding the applicable May filing.




                                                                                                        43
                                                                                                          Exhibit HGL-R-4
                                                                                                        Docket No. 39896
                                                                                                              Page 5 of 5
                                                                                                Page 45.5


                                                                                            Attachment B
                                                                                               Page 2 of 2
                                         ENTERGY TEXAS, INC.
                                 RENEWABLE ENERGY CREDIT RIDER
                                    RATE DEVELOPMENT FORMULA
                                (OVER) / UNDER RECOVERY BALANCE

 Ln                                       Description                                       Amount (1)
 No.                                                                                          ($)
  1    Texas Retail Renewable Energy Credit Costs                                           $        0
  2     Less Rider REC Revenue (2)                                                          $         0
  3    Prior Period (Over) / Under Recovery Balance (3)                                     $         0
  4    (Over) / Under Recovery before Carrying Charges (Sum of Lns 1 thru 3)                $         0
  5    Carrying Costs (4)                                                                   $         0
  6    Cumulative Rider REC (Over) / Under Recovery Balance (Ln 4 + Ln 5)                   $         0
                                                                                                                   N
Notes:
(1)   For the initial filing, the (Over) / Under Recovery Balance is zero. For the initial redetermination,
      the number of months contained in the true-up period used to determine the Initial (Over) / Under
      Recovery Balance will depend upon the effective date of the initial Renewable Energy Credit
      Rate. For subsequent redeterminations, the true-up period used to determine the current (Over) /
      Under Recovery Balance shall be for the twelve (12) months ended December 31 of the
      immediately preceding calendar year.
(2) For the initial redetermination, the number of months of Rider REC Revenue received will depend
      upon the effective date of the initial Renewable Energy Credit Rate. For subsequent
      redeterminations, Rider REC Revenue shall include Rider REC Revenue for the twelve (12)
      months ended December of the immediately preceding calendar year.
(3)   For the initial redetermination, the Prior Period (Over) / Under Recovery Balance shall be zero.
      For subsequent redeterminations, the Prior Period (Over) / Under Recovery Balance shall be
      equal to Cumulative (Over) / Under Recovery Balance (Attachment B, page 2, line 6) as filed in
      the immediately preceding annual Renewable Energy Credit filing.
(4)   Amounts are pursuant to Section IV of this Rider REC. Interest cost shall be calculated based on
      the principles set out in P.U.C. SUBST. R. 25.236(e)(1).




                                                                                                              44
                                 SOAH Docket No. XXX-XX-XXXX
                                         PUC Docket No. 39896
                                            ETI 2011 Rate Case
                                            ETI EXHIBIT NO. 57
                  SOAH DOCKET NO. XXX-XX-XXXX
                     PUC DOCKET NO. 39896

APPLICATION OF ENTERGY         §
TEXAS, INC. FOR AUTHORITY TO   §             BEFORE THE
CHANGE RATES, RECONCILE        §           STATE OFFICE OF
FUEL COSTS, AND OBTAIN         §       ADMINISTRATIVE HEARINGS
DEFERRED ACCOUNTING            §
TREATMENT                      §




                     REBUTTAL TESTIMONY


                               OF

                         PHILLIP R. MAY


                         ON BEHALF OF


                      ENTERGY TEXAS, INC.




                          APRIL 2012




                                                                 1
                          ENTERGY TEXAS, INC.
                   REBUTTAL TESTIMONY OF PHILLIP R. MAY
                            DOCKET NO. 39896


                                TABLE OF CONTENTS

                                                                          Page

I.      Introduction                                                           1 

        A.       Introduction and Qualifications                               1 

        B.       Purpose of Rebuttal Testimony                                 1 

II.     Overall Requested Rate Increase                                        2 

III.    Purchased Power Capacity Cost                                          9 

IV.     The Company's Use of Riders                                           16 

V.      Baseline Values for Transmission, Districution, and Purchased Power   20 

VI.     Affiliate Cost                                                        25 

VII.    Conclusion                                                            31 



                                       EXHIBITS

Exhibit PRM-R-1          Comparison of Costs and Revenue Requirement for Docket
                         Nos. 34800, 37744, and 39896




                                                                               2
     Entergy Texas, Inc.                                                   Page 1 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1                                     I.     INTRODUCTION

2                              A.      Introduction and Qualifications

3    Q.      PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.

4    A.      My name is Phillip R. May. My business address is 639 Loyola Avenue,

5            New Orleans, Louisiana 70113.

6

7    Q.      DID YOU PREVIOUSLY FILE DIRECT TESTIMONY ON BEHALF OF

8            ENTERGY TEXAS, INC. (“ETI” OR “THE COMPANY”) IN THIS

9            PROCEEDING?

10   A.      Yes, I did.

11

12   Q.      DO YOU SPONSOR ANY EXHIBITS OR SCHEDULES IN THIS FILING?

13   A.      I sponsor the Exhibits listed in the Table of Contents.

14

15                             B.     Purpose of Rebuttal Testimony

16   Q.      WHAT IS THE PURPOSE OF THIS TESTIMONY?

17   A.      I will address certain comments and recommendations made by 1) Cities

18           witnesses James Z. Brazell, Mark E. Garrett, Dennis W. Goins, and Karl J.

19           Nalepa, 2) The Kroger Co. witness Kevin Higgins, 3) the Office of Public

20           Utility Counsel (“OPUC”) witness Carol Szerszen, 4) the State Agencies

21           witness Kit Pevoto, and 5) Texas Industrial Energy Consumers witness

22           Jeffry Pollock.




                                                                                     3
     Entergy Texas, Inc.                                                      Page 2 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1                    Specifically, the subjects I will address are:

2               overall requested rate increase

3               purchased power capacity cost and load growth,

4               the Company’s use of riders,

5               establishment of baseline values for transmission, distribution, and

6                purchased power cost, and

7               certain affiliate costs disallowances proposed by OPUC.

8

9                      II.     OVERALL REQUESTED RATE INCREASE

10   Q.      ON PAGE 6, MR. BRAZELL STATES THAT THE COMPANY’S

11           ADJUSTMENTS PROPOSED IN THIS CASE ARE THE SAME THAT IT

12           TOOK IN ITS PRIOR RATE CASE, AND THAT THOSE “DISCREDITED

13           CLAIMS” ULTIMATELY “FORCED’ ETI TO SETTLE THAT CASE AT

14           WELL BELOW ITS REQUEST.                    DO YOU AGREE WITH HIS

15           CHARACTERIZATIONS AND POSITION?

16   A.      No, Mr. Brazell’s claims are completely without merit. First, Mr. Brazell

17           states that the Company was “ultimately forced to settle” for less than

18           Company’s initial request. Settlements are not “forced” upon any party.

19           Each party has within its control the ability to either accept or reject a

20           settlement offer.      Asserting that any party was “forced” to enter into

21           settlement is simply not correct. Also, Mr. Brazell’s own forced logic would

22           apply to the Cities’ claims in Docket No. 37744. In Docket No. 37744, the




                                                                                        4
     Entergy Texas, Inc.                                                                    Page 3 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1             Cities proposed a rate reduction of $6.6 million.1 Using Mr. Brazell’s logic

2             the Cities had similar discredited claims that “forced” the Cities to settle for

3             $75 million more than their filed position.

4

5    Q.       ON PAGE 6, MR. BRAZELL CLAIMS THAT ETI HAS FILED THE SAME

6             RATE CASE IN THIS DOCKET AS IT DID IN DOCKET NO. 37744. DO

7             YOU AGREE?

8    A.       No. In fact Mr. Brazell’s own analysis does not support his conclusion.

9

10   Q.       PLEASE EXPLAIN.

11   A.       The line item detail in Mr. Brazell’s own Exhibit JZB-3 shows that ETI’s net

12            plant has actually grown by $138 million, or 7.5%, from Docket No. 37744

13            to Docket No. 39896.2 The line item detail in Mr. Brazell’s Exhibit JZB-4

14            also shows that non-purchased power O&M has grown by $1.7 million, or

15            0.9%, from Docket No. 37744 to Docket No. 39896.3                       The purchased

16            power capacity cost presented on Mr. Brazell’s Exhibit JZB-4 shows that

17            purchased power capacity cost has increased by $12.1 million, or 4.8%,

18            from Docket No. 37744 to Docket No. 39896.4 I also note that, in his

     1
          Docket No. 37744, Cities Garret direct testimony, page 5, line 13, filed June 9, 2010.
     2
          Exhibit JZB-3, line 1, Docket No. 39896 value of $1.977077 billion compared to Docket
          No. 37744 value of $1.839973 billion.
     3
          Exhibit JZB-4, line 1, Docket No. 39896 value of $211.215 million compared to Docket
          No. 37744 value of $209.555 million.
     4
          Exhibit JZB-4, line 16, Docket No. 39896 value of $267.641 million compared to Docket
          No. 37744 value of $255.492 million.




                                                                                                      5
     Entergy Texas, Inc.                                                               Page 4 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1            Exhibit JZB-4, Mr. Brazell labels this purchased power capacity cost as

2            “Proposed Rider Revenues,” but this cost is more appropriately included in

3            O&M cost to ensure an “apples to apples” comparison, which Mr. Brazell

4            did not do.5

5                    Importantly, one of the largest changes in cost shown on his

6            Exhibit JZB-4 is actually a decrease in cost for depreciation expense in

7            this rate case compared to the prior filing. These types of changes can in

8            no way be interpreted as the Company filing the same case. Moreover, as

9            explained below, his exhibits understate the true differences.

10

11   Q.      IN ADDITION TO THE POINTS YOU MAKE ABOVE, DO MR.

12           BRAZELL’S EXHIBITS JZB-3 AND JZB-4 PROVIDE AN ACCURATE

13           COMPARISON BETWEEN THESE RATE CASES?

14   A.      No. Mr. Brazell also has failed to recognize that he is comparing total

15           company values from Docket No. 37744 to retail values from Docket

16           No. 39896.6




     5
          See Brazell deposition page 34, line 23 through page 35, line 2. Mr. Brazell acknowledges
          that the values on line 16 of his Exhibit JZB-4 that he labels Proposed Rider Revenues are
          purchased power capacity costs.
     6
          See Brazell deposition pages 42-43 where he acknowledged that he was not aware of and
          did not investigate whether these were total company or retail values.




                                                                                                  6
     Entergy Texas, Inc.                                                      Page 5 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1    Q.      HAVE YOU RESTATED MR. BRAZELL’S EXHIBITS JZB-3 AND JZB-4

2            TO REFLECT PROPER COMPARISONS?

3    A.      Yes. Attached as my Exhibit PRM-R-1 is a restatement of Mr. Brazell’s

4            Exhibits JZB-3 and JZB-4. In addition to the filed cases, my exhibit also

5            shows a set of “adjusted” columns which reflect the Company’s rebuttal

6            cases.     Using the Company’s rebuttal cases 1) corrects for the total

7            company value in Docket No. 37744 versus retail in Docket No. 39896

8            issue because the Company’s rebuttal case in Docket No. 37744 adjusted

9            Docket No. 37744 to one that allocates to retail; and 2) corrects for those

10           adjustments/corrections which the Company agreed to and therefore

11           these adjusted columns are more appropriate for the type of comparison

12           Mr. Brazell was attempting to do.

13                    The first page of Exhibit PRM-R-1 shows the rate case detail for

14           O&M expenses and net plant for these three rate cases. Lines 1 and 10

15           of this exhibit show that O&M expenses have increased by $13 million

16           since the last rate case. Lines 11 and 19 of this exhibit show that net plant

17           has increased by $180 million since the last rate case.        Page two of

18           Exhibit PRM-R-1 shows the overall revenue requirement comparison for

19           these rate cases. Line 2, of Page 2 of this exhibit shows that Purchased

20           Power Expense has increased by $32 million; Line 6 shows that

21           depreciation expense has decreased by $29 million; and the overall

22           requested revenue requirement has increased by $35 million in this rate

23           case compared to the prior rate case.



                                                                                        7
     Entergy Texas, Inc.                                                   Page 6 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1                    Again, the scope and scale of changes can in no way be

2            interpreted as the Company filing the same case and can’t even be

3            interpreted as the ETI filing for the same overall revenue requirement,

4            given the $35 million increase mentioned above.

5

6    Q.      ON PAGE 7, MR. BRAZELL STATES THAT ETI’S RETURN ON

7            INVESTMENT HAS REMAINED RELATIVELY CONSTANT.                    PLEASE

8            COMMENT.

9    A.      As mentioned above, Exhibit PRM-R-1 shows that the Company’s

10           investment in net plant has grown by $180 million or 10% in the two years

11           between the test years in ETI’s 2009 rate case and the current 2011 rate

12           cases. This increase in net plant is being offset by other changes. For

13           example, the overall rate of return is less in this rate case compared to

14           that proposed in Docket No. 37744.

15

16   Q.      ON PAGE 9, MR. BRAZELL STATES THAT OPERATING EXPENSES

17           HAVE NOT CHANGED SUBSTANTIALLY BETWEEN CASES. IS THIS

18           CORRECT?

19   A.      No.   This fact is apparent even from Mr. Brazell’s Exhibit JZB-4:    the

20           purchased power capacity cost, shown on line 16, has not been included

21           in his calculation of the Company’s operating expenses. As mentioned

22           above, and as shown on Exhibit PRM-R-1, other O&M costs have

23           increased by $13 million since the last rate case, and purchased power



                                                                                     8
     Entergy Texas, Inc.                                                       Page 7 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1             cost has increased by $32 million since the last rate case.        Even the

2             Cities’ own witness Nalepa states, contrary to Mr. Brazell, that ETI’s

3             purchased power capacity cost has increased by $31 million from the test

4             year to rate year.7

5

6    Q.       ON PAGE 12, MR. BRAZELL STATES THAT HE IS TROUBLED BY ETI

7             RECEIVING $96 MILLION IN RATE INCREASES, AND IS TROUBLED

8             THAT ETI CONSIDERS THAT IT IS AT LIBERTY TO FILE SUCCESSIVE

9             RATE REQUESTS AT THE SAME LEVEL. PLEASE COMMENT.

10   A.       Both Docket No. 34800 and Docket No. 37744 were settled cases and

11            neither settlement imposed a rate freeze that would preclude the

12            Company from filing a rate request at any time in the future. In addition, as

13            discussed above, the Company is not filing the same rate request.

14

15   Q.       WHY HAS THE COMPANY FILED SUCCESSIVE RATE CASES IN

16            RECENT YEARS?

17   A.       The Company has now filed its third rate increase request within the past

18            six years because ETI’s costs continue to grow and, as a result, it

19            continues to under-recover its costs.       A significant driver for these

20            requests is ETI’s purchased power capacity needs, which, under current

21            Commission policy, can only be recovered through base rates.


     7
          Nalepa Direct Testimony, page 11, line 2.




                                                                                         9
     Entergy Texas, Inc.                                                      Page 8 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1                    Mr. Brazell also refers to the “tremendous” cost of these

2            proceedings on the Commission, parties and ratepayers. The Company

3            certainly acknowledges that it incurs substantial costs and resources to

4            prepare, file, and prosecute these cases. However, as noted above, the

5            Company has no choice but to file such cases in an attempt to recover

6            its costs.

7

8    Q.      DO YOU HAVE ANY ADDITIONAL COMMENTS REGARDING WHAT

9            MR. BRAZELL CLAIMS ON HIS PAGE 12 AS “TROUBLING”?

10   A.      Yes. Due to ETI’s relative scale, a cost increase of just $13 million can

11           result in a 100 basis points reduction in the Company’s earned Return on

12           Equity (ROE).       Unfortunately, Mr. Brazell’s own analysis confirms that

13           increases in third-party capacity purchases alone are many multiples of

14           the $13 million. The fact is that ETI has very limited options other than

15           filing successive rate cases in an effort to recover its costs. As noted

16           above, purchased power capacity costs continue to be a significant driver

17           for these requests.            Alternative recovery mechanisms, such as a

18           purchased capacity rider, would provide a more streamlined and efficient

19           approach to cost recovery and would mitigate ETI’s need to file

20           successive rate increase requests.

21                   However, it is rather amazing that in this same testimony,

22           Mr. Brazell states that he is against further use of riders and does not want

23           to establish a baseline for transmission, distribution, and purchased power



                                                                                       10
     Entergy Texas, Inc.                                                      Page 9 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1            costs. Mr. Brazell’s positions contradict themselves. It is disingenuous for

2            him to bemoan the cost of a rate case and yet seek to erect barriers to the

3            very things that could streamline the rate recovery process and mitigate

4            the need for additional costly rate cases. I will discuss each of these

5            topics further below.

6

7         III.    PURCHASED POWER CAPACITY COST AND LOAD GROWTH

8    Q.      ON PAGES 8 AND 18, CITIES WITNESS GOINS RECOMMENDS THAT

9            ETI’S PURCHASED POWER CAPACITY COST BE REDUCED BY $35

10           MILLION DOLLARS.               WHAT IS HIS BASIS FOR MAKING THIS

11           RECOMMENDATION?

12   A.      He states the basis for this adjustment is 1) a reduction in costs for Legacy

13           Affiliate Contracts to reflect more current pricing data; 2) a reduction for

14           Other Affiliate Contracts and Reserve Equalization to reflect more recent

15           contract pricing data and Cities recommended 50 percent reduction in EAI

16           WBL contract; and 3) a reduction in purchased power capacity costs to

17           reflect load growth forecasted to occur.        Company witness Robert

18           Cooper’s rebuttal testimony will address the first two items. I will address

19           the load growth issue.




                                                                                       11
     Entergy Texas, Inc.                                                    Page 10 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1    Q.      ON PAGES 16 THROUGH 18, DR. GOINS SUGGESTS THAT THE

2            COMPANY’S REQUESTED PURCHASED POWER CAPACITY COST

3            SHOULD BE REDUCED TO REFLECT LOAD GROWTH. HOW MUCH

4            HAS DR. GOINS ESTIMATED AS THE LOAD GROWTH ADJUSTMENT?

5    A.      His estimated load growth adjustment is approximately $16 million of the

6            overall $35 million adjustment (disallowance) proposed by Cities.

7

8    Q.      IS A LOAD GROWTH ADJUSTMENT FOR PURCHASED POWER COST

9            APPROPRIATE?

10   A.      No.     The Company’s filed case includes known and measurable

11           purchased power expenses as allowed by Commission Substantive Rule

12           25.231(a).      The Company’s filing has followed the Commission’s

13           requirements, and reflects known and measurable changes of costs,

14           billing determinants, and present revenues, unlike the Cities proposal,

15           which forecasts a load growth adjustment out to December 2013.            A

16           distinct difference between the Company’s filed case and the adjustments

17           proposed by the Cities is that the Cities have proposed a load growth

18           adjustment based on forecasted sales that are not known and

19           measurable. Their excuse for making this adjustment is based on ETI

20           adjusting its purchased power capacity expenses to a rate year level. The

21           Company’s adjustments to its purchased power capacity expense,

22           however, reflect actual signed contracts with known and measurable cost

23           levels and start dates as discussed by Company witness Cooper. These



                                                                                      12
     Entergy Texas, Inc.                                                    Page 11 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1            amounts are known and measurable; Cities’ proposed sales adjustments

2            are not.

3

4    Q.      ON PAGE 17, DR. GOINS STATES THAT ETI IS IMPLICITLY ASKING

5            THE COMMISSION TO IGNORE LOAD GROWTH AND SET RATES IN

6            THIS CASE USING RATE YEAR PURCHASED CAPACITY POWER

7            COSTS AND TEST YEAR BILLING DETERMINANTS.                         PLEASE

8            COMMENT.

9    A.      As discussed above, forecasted sales are not, and cannot, be considered

10           known and measurable.          This is very different from purchased power

11           capacity costs for which contracts have been signed, which result in costs

12           that are known and measurable. As discussed in the rebuttal testimony of

13           Company witness Cooper, ETI is currently short of capacity and would

14           need these rate-year purchases even if ETI load did not grow from the

15           test-year to the rate-year. Therefore, these purchased power costs are

16           clearly consistent with the test year load because they are needed to meet

17           existing ETI load requirements.        It is inappropriate to reduce ETI’s

18           purchased power costs by a load growth adjustment as suggested by

19           Dr. Goins. The Commission should reject Dr. Goins’ adjustment.




                                                                                      13
     Entergy Texas, Inc.                                                 Page 12 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1    Q.      ON PAGE 22, DR. GOINS ALSO CALCULATES AND APPLIES A LOAD

2            GROWTH         ADJUSTMENT      TO   THE   MSS-2   COSTS.      IS   THIS

3            APPROPRIATE?

4    A.      No. As discussed above, a load growth adjustment is not known and

5            measurable. In addition as discussed by Company witness Pat Cicio and

6            as demonstrated by Company witness Mark McCulla, the increase in ETI’s

7            MSS-2 related payments in the rate year is driven by changes in the Net

8            Transmission Investment balances among the Operating Companies.

9            Specifically, changes in ETI’s Net Transmission Investment in the rate

10           year are relatively short versus the other Operating Companies. As a

11           result, ETI must make payments to the other Operating Companies in

12           accordance with MSS-2. This increase in MSS-2 payments is driven by

13           transmission investment; changes in load have a de minimis effect. It is

14           wholly inappropriate to reduce ETI’s MSS-2 expense by a load growth

15           adjustment as suggested by Dr. Goins. The Commission should reject

16           Dr. Goins’ adjustment.

17

18   Q.      ON PAGE 5 AND PAGES 7 THROUGH 18, CITIES WITNESS NALEPA

19           SUGGESTS AN ALTERNATIVE TO DR. GOINS’ ADJUSTMENT TO

20           PURCHASED POWER CAPACITY OF $39 MILLION.                       PLEASE

21           COMMENT ON HIS RECOMMENDATION

22   A.      Initially, as discussed above, the Company’s proposal for rate year cost

23           (based on signed contracts) and test year billing determinants is



                                                                                   14
     Entergy Texas, Inc.                                                    Page 13 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1            consistent with the statute and provides that both the cost and billing

2            determinants reflect known and measurable effects and not a forecasted,

3            unknown level of sales.

4

5    Q.      ON PAGES 9 THROUGH 10, MR. NALEPA DISCUSSES AN EXAMPLE

6            UTILITY AND CAPACITY COST SCENARIO.                IS THIS DISCUSSION

7            RELEVANT?

8    A.      No.    Mr. Nalepa’s example is not relevant because ETI’s situation is

9            neither similar nor analogous to his hypothetical example. Mr. Nalepa

10           assumes an existing utility has 100 kW of load and 100 kW of generation.

11           This utility then grows by 50 kW of load and 50 kW of generation whereby

12           the 50 kW of new generation has different unit costs than the original 100

13           kW.     The distinctions between this example and the facts of the

14           Company’s filed case are that: 1) unlike his example, ETI is and has in the

15           past few years been short on capacity, meaning that even a negative load

16           growth would nevertheless necessitate ETI’s continuing need to acquire

17           additional capacity; 2) the additional 50 kW of generation in Mr. Nalepa’s

18           example may be a known event, however, there is an unknown price and

19           uncertain outcomes, which is in contrast ETI’s situation in that it has

20           signed contracts with known price; and 3) the 50 kW of added load is a

21           forecasted event that is not known to occur.

22                   The primary problem with Mr. Nalepa’s example is that he has

23           assumed that the Company is acquiring this new generation for the sole



                                                                                      15
     Entergy Texas, Inc.                                                      Page 14 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1            purpose of serving new load, but, as discussed in Company witness

2            Cooper’s testimony, this is not the case because ETI is currently short on

3            capacity     The Company’s development of a rate year level of capacity

4            cost is based on actual contracts signed and in place that are necessary

5            to meet the Company’s existing requirements.

6

7    Q.      ON PAGE 11, MR. NALEPA STATES THAT THE COMPANY IS

8            CONTRACTING FOR CAPACITY RESOURCES TO MEET FUTURE

9            DEMAND BUT IS INTENDING TO RECOVER THIS COST FROM

10           CURRENT CUSTOMERS. IS THIS STATEMENT ACCURATE?

11   A.      No.    As described above and in the testimony of Company witness

12           Cooper, ETI is short of capacity now. It is not accurate to assume that

13           capacity is being purchased solely to meet the requirements for future

14           load. In fact, the Company’s development of a rate year level of capacity

15           cost reflects a level of resources that still requires ETI to purchase reserve

16           capacity through MSS-1. In other words, the Company remains relatively

17           short in the rate year.

18

19   Q.      ON PAGE 23, TIEC WITNESS POLLOCK DISCUSSES LOAD GROWTH.

20           WHAT DOES TIEC PROPOSE?

21   A.      Rather than make a load growth adjustment as suggested by Cities, and

22           discussed above, Mr. Pollock suggests: 1) make no load growth




                                                                                        16
     Entergy Texas, Inc.                                                   Page 15 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1            adjustment, and 2) ignore the rate-year purchases and instead revert to

2            test-year values.

3

4    Q.      ON PAGE 23, MR. POLLOCK STATES THAT THE ADDITIONAL

5            PURCHASED POWER COST IS DUE TO MEETING FUTURE LOADS.

6            IS THIS STATEMENT CORRECT?

7    A.      No. As discussed extensively above and in Company witness Cooper’s

8            rebuttal testimony, the Company’s development of a rate year level of

9            capacity cost reflects a level of resources that still requires ETI to

10           purchase reserve capacity through MSS-1; it remains relatively short.

11

12   Q.      ON PAGE 23, MR POLLOCK CLAIMS THAT ETI’S PROPOSAL HAS

13           VIOLATED THE MATCHING PRINCIPLE.                 IS THIS STATEMENT

14           CORRECT?

15   A.      I disagree with Mr. Pollock, as discussed above, the Company’s filing has

16           followed the statutory requirements, and reflects known and measurable

17           changes of costs, billing determinants, and present revenues.      In any

18           event, Mr. Pollock’s arguments carry no weight. As also discussed above,

19           these purchased power capacity costs are required to meet ETI’s current

20           load, not a future load.




                                                                                     17
     Entergy Texas, Inc.                                                    Page 16 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1                             IV.     THE COMPANY’S USE OF RIDERS

2    Q.       ON PAGES 14 AND 15, MR. BRAZELL LISTS ETI’S CURRENT AND

3             PROPOSED              RIDERS   AND   STATES   THAT    ETI   CURRENTLY

4             RECOVERS A LARGE PORTION OF ITS COSTS THROUGH RIDERS.

5             PLEASE COMMENT.

6    A.        Mr. Brazell lists 11 riders. Of these 11, the Purchased Power Rider has

7             been removed from this case and thus the list of riders is really only 10.

8             Of these remaining 10, he agrees that some are necessary and

9             appropriate, specifically the four energy efficiency and “storm” riders.8

10            Energy efficiency would be Rider EECRF in his list in Table 3 on page 15,

11            and storm riders are Riders HRC, SRC, and SCO. Of the remaining 6

12            riders: 1) Rider TTC was implemented and approved in accordance with

13            PURA § 39.454 to recover ETI’s (then Entergy Gulf States, Inc’s Texas

14            utility) transition to competition costs incurred prior to September 2005;

15            2) Rider RCE is the rider proposed in this docket for recovery of the

16            Company’s (and Cities’) rate case expenses incurred in this docket;

17            3) Rider REC is proposed in this docket for recovery of the Company’s

18            renewable energy credit costs incurred pursuant to PURA § 39.904;

19            4) Rider IFFR is for recovery of incremental franchise fees incurred by

20            ETI. It is a rider that was extended in accordance with the unopposed

21            settlement agreement entered into and approved in Public Utility


     8
          Brazell direct, page 15, line 4.




                                                                                      18
     Entergy Texas, Inc.                                                        Page 17 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1            Commission of Texas (“PUCT”) Docket No. 34800 and this rider is

2            authorized by PURA § 39.456. The two remaining riders on Mr. Brazell’s

3            list (“TCRF” and “DCRF”) pertain to transmission cost recovery and

4            distribution cost recovery mechanisms, both authorized by PURA § 36.209

5            and PURA § 36.210, respectively, that have not yet been filed for or

6            implemented by ETI. Rather, ETI has requested, and the Commission

7            has agreed, that baseline values for these two future TCRF and DCRF

8            riders be established in this docket so as to avoid needing to file a future

9            rate case to establish these values (see discussion above regarding

10           successive rate cases and discussion below regarding establishment of a

11           baseline for TCRF and DCRF). These six riders (that is, not the EECRF

12           or storm-related riders), only recover approximately $12 million annually.

13           This in no way should be interpreted as an “expansive use of riders” as

14           claimed by Mr. Brazell. These six riders are the sum of his complaint. It is

15           not the $381 million listed in his table. These riders evolved from special

16           circumstances, are approved by the Commission and implemented in

17           accordance with rider-specific PURA provisions, PUCT rules, or ETI

18           settlements agreed to by Cities.         Mr. Brazell acknowledged in his

19           deposition      that    his    primary   concern   with   riders      in    this

20




                                                                                          19
     Entergy Texas, Inc.                                                                Page 18 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1             case was with the PPR rider. He further acknowledged that the PPR rider

2             is no longer an issue for the case.9

3

4    Q.      ON PAGES 16 AND 17, MR. BRAZELL ARGUES THAT ETI’S RIDERS

5             (WHETHER IN EFFECT OR PROPOSED) VIOLATE “PIECEMEAL

6             RATEMAKING” PRINCIPLES. DO YOU AGREE?

7    A.      No, I do not. Piecemeal ratemaking is a term that opponents of alternative

8             ratemaking often use to encompass any streamlined rate mechanism that

9             departs from traditional rate-setting practice by allowing rate adjustments

10            to specific cost components outside a full rate case. Opponents often

11            argue that “piecemeal ratemaking” is prohibited by statute. In fact, a

12            number of different streamlined rate riders and cost recovery factors that

13            might be viewed as piecemeal are expressly authorized under PURA and

14            have been approved by the Commission over the last ten years.                       For

15            example, Riders TCRF and DCRF have been specifically authorized by

16            this Commission, and timely recovery of purchased power capacity costs

17            through a rider is currently subject to a rulemaking proceeding opened by

18            the Commission.10




     9
          Brazell deposition page 61 through 62. Brazell direct testimony page 18, line 3 through 7 he
          refers to PPR, TCRF and DCRF being his primary concern.
     10
          Rulemaking Proceeding Concerning Recovery of Purchased Power Capacity Costs,
          Including Amendment of SUBST. R. § 25.238, PUCT Project No. 39296 (initiated March 10,
          2011).




                                                                                                   20
     Entergy Texas, Inc.                                                    Page 19 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1    Q.      ON PAGE 17, CITIES WITNESS NALEPA STATES THAT THE

2            PURCHASED POWER BASELINE ESTABLISHED IN THIS RATE CASE

3            SHOULD BE ON A $/KW BASIS. PLEASE COMMENT.

4    A.      It can be anticipated that the proper denominator and application of a

5            $/kW baseline will be debated in the purchased power capacity rulemaking

6            referenced above.        Parties will likely argue whether the denominator

7            should be load or the capability of purchases, and whether load growth

8            should be reflected and, if so, how. The Company, along with all other

9            parties, should not be precluded from making arguments they deem

10           appropriate in that rulemaking proceeding by setting a $/kW value in this

11           docket as suggested by Mr. Nalepa. Instead, to ensure that a purchased

12           power capacity baseline developed in this docket can be used in the

13           capacity recovery mechanism ultimately approved in the rulemaking

14           proceeding, that baseline should be established on a dollar basis, with the

15           appropriate measure and evaluation of changes in this baseline left to be

16           set in that rulemaking proceeding.




                                                                                      21
     Entergy Texas, Inc.                                                        Page 20 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1         V.         BASELINE VALUES FOR TRANSMISSION, DISTRIBUTION, AND
2                                  PURCHASED POWER

3    Q.        ON PAGES 18 AND 19, MR. BRAZELL STATES “INSTEAD OF

4              ATTEMPTING TO FASHION BASELINES IN THIS CASE” THE

5              COMPANY SHOULD INSTEAD BE REQUIRED TO FILE AN UPDATED

6              SCHEDULED P AS PART OF A COMPLIANCE FILING AT THE END OF

7              THIS     PROCEEDING,         AND     THAT     WOULD        PROVIDE       ANY

8              INFORMATION RELEVANT TO “SETTING A POSSIBLE FUTURE TCRF

9              OR DCRF.” DO YOU AGREE?

10   A.        No. The Supplemental Preliminary Order issued in this docket on January

11             19, 2012, at pages 2-4, states that an issue to be addressed in this case

12             is:   “What are the baseline values that should be used for calculating

13             Entergy’s future transmission cost recovery factor and distribution cost

14             recovery factor.” This is a specific directive that the baselines be set in

15             this docket.

16                     As the Company explained in its briefing on threshold legal/policy

17             issues in this case, ETI is not asking the Commission to establish values

18             other than those that will be needed to implement a TCRF and DCRF in

19             the future consistent with the applicable rules. In most rate cases, these

20             baseline values would be embedded in the various memos or schedules

21             that support the final order in the rate case. By specifically identifying the

22             baseline values, the Commission will help the parties in future cases avoid

23             disputes regarding how such memos and/or schedules should be




                                                                                          22
     Entergy Texas, Inc.                                                   Page 21 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1            construed in determining the appropriate baseline values.     Mr. Brazell

2            acknowledged in his deposition that Schedule P would not be in sufficient

3            detail to establish baseline values for certain FERC accounts anyway.11

4            Therefore, Mr. Brazell’s suggestions should be rejected and baseline

5            values for purchased power, transmission, and distribution should be

6            established in this docket in sufficient detail to facilitate future TCRF,

7            DCRF, or purchased power filings (assuming the purchased power

8            rulemaking establishes those procedures).

9

10   Q.      ON PAGES 5 AND 16-17, STATE WITNESS PEVOTO RECOMMENDS

11           THAT WHEN SETTING THE BASELINE FOR PURCHASED POWER

12           COST IN THIS DOCKET, THE BASELINE SHOULD BE LIMITED TO

13           PURCHASED            CAPACITY   COSTS     ASSOCIATED       WITH     NON-

14           AFFILIATED        THIRD-PARTY   CONTRACTS,       AND    NOT     INCLUDE

15           “LEGACY, AND OTHER AFFILIATE CONTRACTS AND RESERVE

16           EQUALIZATION PURCHASES.” WHAT IS YOUR UNDERSTANDING OF

17           HER POINTS?

18   A.      Ms. Pevoto states that the Company’s affiliate-related purchased capacity

19           contracts are essentially agreements “set up to share centralized planned

20           generation capacity resources among Entergy Operating Companies” and

21           are not market competitive contracts.


     11
          Brazell deposition pages 69-73.




                                                                                     23
     Entergy Texas, Inc.                                                      Page 22 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1    Q.      ARE MS. PEVOTO’S ASSERTIONS CORRECT?

2    A.      No.    Her comments do not fully reflect the current nature of these

3            transactions. The affiliate-related transactions are beneficial to ETI from

4            both pricing and flexibility purposes, and therefore are beneficial to ETI’s

5            customers. These transactions have been market-tested and should not

6            be removed from a purchased capacity baseline.            For example, the

7            Perryville and Calcasieu purchases are examples of capacity that was

8            purchased on the open market as a result of a bidding process and are

9            simply priced to ETI from EGSL using the MSS-4 service schedule. A

10           somewhat different example would be the Calpine-Carville purchase,

11           described in the direct testimony of Company witness Cooper, whereby

12           ETI is purchasing the capacity of this facility from an external non-affiliate

13           third-party and is then selling 50% of this capacity to Entergy Gulf States

14           Louisiana, LLC via an affiliate transaction using MSS-4. It is unclear from

15           Ms. Pevoto’s recommendation whether she is suggesting that the full

16           amount of the purchase be reflected in the baseline, but not the 50% sale

17           to EGSL because it is an affiliate transaction.

18                   Affiliate transactions and their pricing based on MSS-4 are simply

19           being used by the Entergy System to maintain maximum flexibility and

20           efficiency in the acquisition of capacity. Ms. Pevoto’s suggestion would

21           imply that the Company should no longer seek any affiliate transaction

22           and only negotiate purchases whereby ETI is the sole purchaser. This is

23           an unrealistic constraint on the flexibility of ETI to acquire capacity given



                                                                                        24
     Entergy Texas, Inc.                                                     Page 23 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1            its relative small size and the inefficiency of forcing ETI to negotiate

2            individual deals for itself that can instead be negotiated by ESI on behalf

3            of all the Entergy Operating Companies.       The Commission should not

4            preclude the Company and its customers from seeking beneficial

5            contracts just because they fit in a category of “affiliate purchases.” In

6            addition, it is my understanding that requiring ETI to only purchase

7            capacity whereby it is the sole purchaser and no other affiliate is involved

8            is in direct violation of the System Agreement.

9

10   Q.      DOES      THE      STATE’S     PROPOSAL     TO    DETERMINE      IN    THIS

11           PROCEEDING THE SCOPE OF COSTS TO BE INCLUDED IN A

12           FUTURE PPR RAISE ANY OTHER CONCERN?

13   A.      Yes. It is inappropriate to bind parties to positions they may, or may not,

14           take in the purchased power rulemaking at this time. If, on the other hand,

15           the Commission wishes to consider these issues in this docket it is the

16           Company’s position that the best way to design a purchased power rider is

17           to exclude all purchased power from base rates to ensure no over- or

18           under- recovery of this cost through base rates. Thus, the Commission

19           should reject the State’s proposal.




                                                                                       25
     Entergy Texas, Inc.                                                              Page 24 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1    Q.       DO YOU AGREE WITH INTERVENOR SUGGESTIONS TO STATE THE

2             PURCHASED POWER BASE LINE VALUE ON A UNIT BASIS (E.G.,

3             $/MW OR MW-MO)?12

4    A.       No. The intervenors’ use of a unit value for purchased power is part and

5             parcel of their arguments on the effects of load growth. Adoption of their

6             proposal to use a unit value as a base line would pre-determine that load

7             growth should be taken into account and how it should be taken into

8             account in any future rider that may be adopted as part of the pending

9             rulemaking on this subject. That is a policy issue that must be considered

10            by the Commission as part of the rulemaking, where all interested parties

11            who may be affected by a proposed rule have an opportunity to weigh in

12            on the appropriate policy to be adopted. As to the purchased power base

13            line, the purpose of this contested case proceeding is only to set a

14            baseline that can be used in future proceedings to support a rider, not to

15            determine how that baseline should be used in any future rider. The ALJs

16            and Commission can make base line findings on the total dollars for

17            purchased power and, if necessary, the volume (MW) so that parties have

18            sufficient information to advance their positions on the appropriate method

19            to reflect load growth as part of a future proceeding.




     12
          Nalepa direct at page 17, lines 11-16. Pollock direct at page 27, line 7.




                                                                                                26
     Entergy Texas, Inc.                                                         Page 25 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1                                     VI.      AFFILIATE COST

2    Q.      ON PAGE 48, OPUC WITNESS SZERSZEN ADJUSTS AFFILIATE

3            COSTS       BY     $759,868       FOR   PROJECTS         F3PCSYSRAS          AND

4            F3PCSYSRAF. PLEASE DESCRIBE THESE TWO PROJECT CODES.

5    A.      The affiliate charges to Project Codes F3PCSYSRAS and F3PCSYSRAF

6            are directly associated with the issues and matters within the federal

7            jurisdiction of the Federal Energy Regulatory Commission (“FERC”)

8            including but not limited to the Open Access Transmission Tariff (“OATT”)

9            as well as any other federal statutes, rules and regulations. These are the

10           result of issues and matters raised concerning the OATT, operations of

11           the   transmission      system,    requests   for   transmission   service   and

12           interpretation of applicable provisions under the jurisdiction of FERC.

13           They are costs incurred on an Entergy System-wide basis that cannot be

14           directly assigned to any one Operating Company, such as ETI. Further,

15           the affiliate test year issues and costs related to these project codes are

16           reflective of typical issues and costs that the Company experiences on an

17           ongoing basis. These issues and matters, once resolved, do not result in

18           the permanent conclusion of issues and matters. Similar type of issues

19           and matters, as well as new issues and matters, are commonly and

20           repeatedly raised concerning operations and interpretations of applicable

21           provisions under the jurisdiction of FERC.




                                                                                           27
     Entergy Texas, Inc.                                                       Page 26 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1    Q.      WHAT ARE THE REASONS GIVEN BY DR. SZERSZEN FOR

2            DISALLOWING THESE COSTS?

3    A.      Dr. Szerszen seems to base her proposal on three arguments: 1) that

4            Texas is being allocated costs associated with FERC dockets that are not

5            related to ETI electric operations and transmission issues; 2) that FERC

6            dockets identified with project code F3PCSYSRAF are no longer active;

7            and 3) the use of either a customer count or load responsibility ratio for

8            allocation purposes to allocate this cost to ETI is not appropriate.

9                    As to her first point, Dr. Szerszen states that there is “no evidence

10           that Texas ratepayers are receiving any specific benefits from ‘system’

11           regulatory affairs costs in proportion to the allocated costs.” That is simply

12           not true. My testimony on the affiliate costs in my Regulatory Support

13           Affiliate Class, as well as the affiliate testimony of all other ETI affiliate

14           class witnesses, provides ample evidence of the reasonableness and

15           necessity of these costs. In addition to the proof of reasonableness and

16           necessity shown in the Company’s affiliate case, ETI benefits because

17           these are costs incurred by a centralized service company (ESI) to

18           support all of the Entergy Operating Companies, rather than ETI bearing

19           the costs of these services wholly on its own. In addition, ETI is required

20           to participate in Entergy’s OATT, routine filings of the OATT are required

21           by the FERC, and Entergy’s participation in these dockets protects the

22           interest of ratepayers since the OATT revenues are credited to the retail

23           revenue requirement.



                                                                                         28
     Entergy Texas, Inc.                                                       Page 27 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1    Q.      ON PAGE 48, DR. SZERZSEN REFERS TO ETI’S RESPONSE TO

2            OPUC RFI 2-10 THAT LISTS 10 FERC-RELATED DOCKETS, WHICH

3            SHE SAYS WERE ASSOCIATED WITH “MISCELLANEOUS FILINGS AT

4            FERC” AND THAT ARE NO LONGER ACTIVE.                       WHAT IS YOUR

5            RESPONSE?

6    A.      First, Dr. Szerszen does not state that these costs were not incurred, or

7            were incurred outside of the test year. These costs were actually incurred.

8            Second, these affiliate charges are ordinary, necessary and similar in

9            nature to issues and matters that occur, and cost that are incurred, on an

10           annual basis. These issues and matters, once resolved, do not result in

11           the permanent conclusion of issues and matters. These same issues

12           (e.g., FERC rulemakings or other filings), and similar types of issues and

13           matters are commonly and repeatedly raised concerning operations and

14           interpretations of applicable provisions under the jurisdiction of FERC. Dr.

15           Szerszen’s characterization of these cases answers her own concern with

16           regard to these ten cases. They were “miscellaneous filings.” Entergy

17           Services, Inc., on behalf of all of the Entergy Operating Companies,

18           makes numerous miscellaneous filings at the FERC every year throughout

19           the year. These test year costs, therefore, are representative of the costs

20           incurred and then allocated to ETI and all the other Entergy Operating

21           Companies on an ongoing basis.

22                   Any activity at FERC that would affect ETI, either directly or

23           indirectly (e.g., through ESI), is promptly identified and a plan of resolution



                                                                                         29
     Entergy Texas, Inc.                                                      Page 28 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1            is developed.       With respect to SYSRAF, coordination of regulatory

2            strategy between the various state regulatory organizations ensures that

3            efforts are efficiently expended toward a common goal.           Further, the

4            benefit to ETI involves a multitude of issues that are directly related to the

5            jurisdiction of the FERC, including but not limited to any revisions to

6            Service Schedules under the System Agreement that applies to all

7            operating companies including ETI, power purchase agreements for cost-

8            based, short-term power sales, and compliance with FERC by each

9            Operating Company to the market-based rate tariff and cost-based rate

10           tariff.   The Entergy Operating Companies’ market-based rate tariff and

11           cost-based rate tariff are joint tariffs containing terms and conditions of

12           service.

13                     These costs, therefore, should not be disallowed and have been

14           shown, through testimony, to meet the Commission’s affiliate cost

15           recovery standard.

16

17   Q.      PLEASE COMMENT ON THE BILLING ALLOCATION METHODOLOGY

18           UTILIZED FOR THESE TWO PROJECT CODES.

19   A.      Project Code F3PCSYSRAF utilizes billing method “LOADOPCO” to

20           allocate costs to each Entergy Operating Company. As discussed in my

21           direct testimony, this billing method is based on the load responsibility of

22           the regulated companies.       Project Code F3PCSYSRAF captures costs

23           associated with oversight of FERC activities for the Entergy Operating



                                                                                        30
     Entergy Texas, Inc.                                                       Page 29 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1            Companies to ensure that the issues affecting, and interests of, the

2            Companies and their customers at the FERC are adequately addressed.

3            The primary activities associated with this project code include, but are not

4            limited to: preparation of filings, testimony and other documents; response

5            to requests for information in regulatory proceedings; meeting with FERC

6            Staff; and oversight activities. What drives the cost of this project code

7            are labor, employee expenses, consultants and other general operating

8            expenses incurred for the benefit of the Entergy Operating Companies

9            and their regulated customers. Therefore, a billing method based on load

10           responsibility is appropriate for this type of project code.

11                   Project Code F3PCSYSRAS utilizes billing method “CUSTEGOP”

12           to allocate costs to each Operating Company. As discussed in my direct

13           testimony, this billing method is based on the average number of electric

14           and gas customers of the regulated companies.                  Project Code

15           F3PCSYSRAS captures costs associated with general regulatory support

16           work that is applicable across all of the jurisdictions. The primary activities

17           associated in this project code include but are not limited to: special

18           project work associated with system-wide regulatory matters, analysis of

19           emerging state or national regulatory and accounting issues affecting the

20           Entergy System, and internal process improvement work. What drives the

21           cost of this project code is the average number of both electric and gas

22           customers served because all such customers benefit from these services

23           provided by ESI to ETI.



                                                                                         31
     Entergy Texas, Inc.                                                     Page 30 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1                    These billing methods appropriately assign costs to each Operating

2            Company, including ETI, based on their responsibility. Dr. Szerszen has

3            not suggested what billing method would be more appropriate and, even if

4            she did, those that have been applied to these two project codes are

5            appropriate for the reasons stated above.

6

7    Q.      ON PAGES 69 AND 70, OPUC WITNESS SZERSZEN ADJUSTS

8            AFFILIATE COSTS BY $171,032 FOR PROJECT CODE F3PPE9981S.

9            PLEASE DESCRIBE THIS PROJECT CODE.

10   A.      The primary products or deliverables of this project are the services of the

11           Integrated Energy Management department, discussed in my direct

12           testimony, to coordinate and deliver results of AMI, Smart Grid, energy

13           efficiency, demand-side management, technology, renewables, climate

14           change, and supply-side management.

15

16   Q.      ON PAGE 70, OPUC WITNESS SZERSZEN SUGGESTS THAT ALL ETI

17           ENERGY EFFICIENCY AND DSM ACTIVITY SHOULD BE RECOVERED

18           IN RIDER EERC. HOW DO YOU RESPOND?

19   A.      The Company has proposed recovery of these costs through base rates

20           rather than through the EECRF Rider because these activities are not

21           subject to an active ETI energy efficiency program. These activities are

22           more in the nature of general research and development activities that

23           help drive the Company’s strategy on these topics, such as the timing of



                                                                                       32
     Entergy Texas, Inc.                                                     Page 31 of 31
     Rebuttal Testimony of Phillip R. May
     Docket No. 39896


1            implementing related programs.       In the meantime, until these activities

2            result in an actual program proposal, these are legitimate known and

3            measurable costs that the Company has incurred and should then be

4            recovered from retail customers. Therefore, the costs that Dr. Szerszen

5            addresses on these pages are properly allocated and billed, are not in the

6            EECRF, and, therefore, should be allowed.

7

8                                       VII.   CONCLUSION

9    Q.      DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY?

10   A.      Yes.




                                                                                       33
                                                          ETI O&M EXPENSES, NET PLANT IN SERVICE COMPARISON
                                                                     DOCKET NOS. 34800, 37744, 39896
                                                                                 (000)

                                                                  (a)             (b)             (c)            (d)               (e)             (f)            (g)
                                                                Filed            Filed         Adjusted      Increase to          Filed         Adjusted      Increase to
     Line   Item                                            Docket # 34800   Docket # 37744 Docket # 37744 Docket # 37744     Docket # 39896 Docket # 39896 Docket # 39896

       1    O&M Expenses                                    $      236,448   $     209,555    $    194,671    $    (41,777)   $     211,215    $    207,882    $    13,211

      2      Production                                     $       65,683   $      47,933    $     44,698    $    (20,985)   $      46,124    $     46,124    $     1,426
      3      Transmission                                   $       26,774   $      18,811    $     18,296    $     (8,478)   $      29,708    $     29,708    $    11,412
       4     Regional Market                                $          -     $         -      $        -      $        -      $       4,091    $      4,091    $     4,091
       5     Distribution                                   $       31,399   $      36,870    $     36,681    $      5,282    $      30,703    $     30,703    $    (5,978)
       6     Customer Accounting                            $       20,214   $      19,260    $     18,320    $     (1,894)   $      17,273    $     17,273    $    (1,047)
       7     Customer Services                              $        4,199   $       5,600    $      5,600    $      1,401    $       4,421    $      4,421    $    (1,179)
       8     Sales                                          $          143   $       1,108    $      1,074    $        931    $       1,094    $      1,094    $        20
       9     Administrative & General                       $       88,036   $      79,973    $     70,002    $    (18,034)   $      77,801    $     74,468    $     4,466
      10                                                    $      236,448   $     209,555    $    194,671    $    (41,777)   $     211,215    $    207,882    $    13,211

      11    Net Plant in Service                            $    2,039,677   $    1,839,973   $   1,797,050   $   (242,627)   $    1,977,077   $   1,977,077   $   180,027

      12     Production                                     $      702,930   $      299,705   $     277,828   $   (425,102)   $      295,575   $     295,575   $    17,747
      13     Transmission                                   $      467,357   $      538,696   $     523,071   $     55,714    $      604,506   $     604,506   $    81,435
      14     Regional Market                                $          -     $        3,257   $       3,163   $      3,163    $        1,885   $       1,885   $    (1,278)
      15     Distribution                                   $      780,981   $      890,975   $     889,283   $    108,302    $      964,109   $     964,109   $    74,826
      16     General Plant                                  $       55,874   $       75,393   $      72,693   $     16,819    $       81,943   $      81,943   $     9,250
      17     Intangible Plant                               $       32,535   $       29,443   $      28,508   $     (4,027)   $       26,321   $      26,321   $    (2,187)
      18     Specific Assignment                            $          -     $        2,504   $       2,504   $      2,504    $        2,738   $       2,738   $       234
      19                                                    $    2,039,677   $    1,839,973   $   1,797,050   $   (242,627)   $    1,977,077   $   1,977,077   $   180,027
      20    Net Plant in Service - Excluding Production     $    1,336,747   $    1,540,268   $   1,519,222   $    182,475    $    1,681,502   $   1,681,502   $   162,280




34
                                                                                                                                                                          Page 1 of 2
                                                                                                                                                                   2011 TX Rate Case
                                                                                                                                                                     Exhibit PRM-R-1
                                                           ETI REVENUE REQUIREMENT COMPARISON
                                                                DOCKET NOS. 34800, 37744, 39896
                                                                            (000)

                                                           (a)              (b)             (c)            (d)               (e)             (f)            (g)
                                                         Filed             Filed         Adjusted      Increase to          Filed         Adjusted      Increase to
     Line   Item                                     Docket # 34800    Docket # 37744 Docket # 37744 Docket # 37744     Docket # 39896 Docket # 39896 Docket # 39896

      1     O&M Expenses                             $      236,448    $      209,555    $   194,671    $    (41,777)   $      211,215    $    207,882    $    13,211
      2     O&M - Purchased Power Expenses           $       52,420    $      254,864    $   231,360    $    178,940    $      266,934    $    263,078    $    31,718
      3     O&M - Renewable Energy Credit Expenses   $          -      $          627    $       -      $        -      $          631    $      1,160    $     1,160
      4     Interest on Customer Deposits            $        1,535    $        1,276    $       162    $     (1,373)   $            69   $          69   $       (93)
      5     Regulatory Debits & Credits              $        2,035    $        5,056    $     4,750    $      2,715    $        5,004    $      5,004    $       254
      6     Depreciation & Amortization Expense      $       86,576    $      126,968    $   123,518    $     36,942    $       97,100    $     94,722    $   (28,796)
      7     Decommissioning Expenses                 $        3,671    $          -      $       -      $     (3,671)   $          -      $        -      $       -
       8    Taxes Other Than Income                  $       47,238    $       55,436    $    54,589    $      7,351    $       59,852    $     62,552    $     7,963
       9    Current Income Taxes                     $       66,258    $       63,793    $    62,064    $     (4,194)   $       41,114    $     40,946    $   (21,118)
      10    Deferred Income Taxes                    $       (4,918)   $       (4,197)   $    (4,331)   $        587    $       14,618    $     14,618    $    18,949
      11    ITC Amortization                         $       (2,574)   $       (1,609)   $    (1,560)   $      1,014    $       (1,630)   $     (1,630)   $       (70)
      12    Total Expenses                           $      488,689    $      711,769    $   665,223    $    176,534    $      694,907    $    688,401    $    23,178
      13    Return Requested                         $      151,474    $      153,232    $   129,077    $    (22,397)   $      149,060    $    148,584    $    19,507
      14    Other Revenue/Sales Credits              $      (44,607)   $     (123,464)   $   (96,324)   $    (51,717)   $     (103,776)   $   (103,776)   $    (7,452)
      15    Energy Efficiency Expenses               $        3,944    $          -      $       -      $     (3,944)   $          -      $        -      $       -
      16    Miscellaneous Service Fees               $        5,041    $          -      $       -      $     (5,041)   $          -      $        -      $       -
      17    Public Benefit Fund                      $        5,059    $          -      $       -      $     (5,059)   $          -      $        -      $       -
      18    Requested Revenue Requirement            $      609,600    $      741,537    $   697,976    $     88,376    $      740,191    $    733,209    $    35,233




35
                                                                                                                                                                     Page 2 of 2
                                                                                                                                                              2011 TX Rate Case
                                                                                                                                                                Exhibit PRM-R-1
                                 SOAH Docket No. XXX-XX-XXXX
                                         PUC Docket No. 39896
                                            ETI 2011 Rate Case
                                            ETI EXHIBIT NO. 59
                  SOAH DOCKET NO. XXX-XX-XXXX
                     PUC DOCKET NO. 39896


APPLICATION OF ENTERGY         §
TEXAS, INC. FOR AUTHORITY TO   §             BEFORE THE
CHANGE RATES, RECONCILE        §           STATE OFFICE OF
FUEL COSTS, AND OBTAIN         §       ADMINISTRATIVE HEARINGS
DEFERRED ACCOUNTING            §
TREATMENT                      §




                     REBUTTAL TESTIMONY


                               OF


                       MARK F. MCCULLA


                         ON BEHALF OF


                     ENTERGY TEXAS, INC.




                          APRIL 2012




                                                                 1
                        ENTERGY TEXAS, INC.
               REBUTTAL TESTIMONY OF MARK F. MCCULLA
                          DOCKET NO. 39896


                             TABLE OF CONTENTS

                                                                          Page

I.     Introduction                                                           1

       A. Introduction and Qualifications                                     1

       B. Purpose of Rebuttal Testimony                                       1

II.    Transmission Equalization                                              2

III.   Affiliate Expenses                                                     8

IV.    Conclusion                                                            12



                                    EXHIBITS

Exhibit MFM-R-1       Projects Included in MSS-2 Projections for June 2012 – May
                      2013

Exhibit MFM-R-2       ETI’s Response to OPUC 6-5 in PUCT Docket No. 37744




                                                                              2
     Entergy Texas, Inc.                                                   Page 1 of 12
     Rebuttal Testimony of Mark F. McCulla
     Docket No. 39896


 1                                   I.      INTRODUCTION

 2                            A.     Introduction and Qualifications

 3   Q.     PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.

 4   A.     My name is Mark F. McCulla.           My business address is 639 Loyola

 5          Avenue, New Orleans, Louisiana 70113.

 6

 7   Q.     DID YOU PREVIOUSLY FILE DIRECT TESTIMONY ON BEHALF OF

 8          ENTERGY TEXAS, INC. (“ETI” OR “THE COMPANY”) IN THIS

 9          PROCEEDING?

10   A.     Yes, I did.

11

12   Q.     DO YOU SPONSOR ANY EXHIBITS IN THIS FILING?

13   A.     Yes, I sponsor the exhibits listed in the Table of Contents.

14

15                           B.      Purpose of Rebuttal Testimony

16   Q.     WHAT IS THE PURPOSE OF THIS TESTIMONY?

17   A.     The purpose of my rebuttal testimony is to address opinions of Mr. Jeffry

18          Pollock and Dr. Dennis Goins regarding the transmission equalization

19          expenses proposed by ETI in this docket. In addition, I address Dr. Carol

20          Szerszen’s erroneous conclusion regarding the affiliate charges for

21          providing rental space on the Company’s transmission poles.




                                                                                     3
     Entergy Texas, Inc.                                                  Page 2 of 12
     Rebuttal Testimony of Mark F. McCulla
     Docket No. 39896


 1                         II.     TRANSMISSION EQUALIZATION

 2   Q.     WHAT       AMOUNT        HAS     ETI   PROPOSED   FOR    TRANSMISSION

 3          EQUALIZATION PAYMENTS FOR THE RATE YEAR?

 4   A.     $10.697 million.

 5

 6   Q.     WHAT       TRANSMISSION          INVESTMENTS      WERE   INCLUDED      IN

 7          DETERMINING ETI’S PROPOSED EQUALIZATION PAYMENTS?

 8   A.     The proposed $10.697 million in transmission equalization payments is

 9          based on $184.9 million in additional transmission equalizable Total

10          Investment across the Entergy Transmission System, including ETI’s, for

11          the period of June 2012 through May 2013.

12

13   Q.     WHAT PROJECTS ARE INCLUDED IN THE PROJECTED $184.9

14          MILLION OF TRANSMISSION EQUALIZABLE TOTAL INVESTMENT?

15   A.     Exhibit MFM-R-1 provides a summary of the six highest-cost projects

16          included in the projected equalizable Total Investment. These projects

17          comprise $141.0 million of the total $184.9 million. As seen in Exhibit

18          MFM-R-1, funding for each of these projects has been approved, and

19          each is progressing on schedule in the design or construction phase, with

20          the latest in-service date scheduled for December 31, 2012. In fact, one

21          of these projects – the 230 kV line from Loblolly to Hammond – was put in

22          service on December 16, 2011.




                                                                                    4
     Entergy Texas, Inc.                                                 Page 3 of 12
     Rebuttal Testimony of Mark F. McCulla
     Docket No. 39896


 1   Q.     WHAT PROJECTS ARE INCLUDED IN THE REMAINING $43.9 MILLION

 2          OF TRANSMISSION EQUALIZABLE TOTAL INVESTMENT?

 3   A.     The remaining $43.9 million is an estimate of the capital investment

 4          necessary to maintain equalizable transmission investments across the

 5          Entergy Transmission System. This estimate is based on the Entergy

 6          Operating Companies’ projected budget and historical spending for

 7          maintenance of these facilities.

 8

 9   Q.     MR. POLLOCK ASSERTS (PAGE 32) THAT ETI’S PROPOSED

10          TRANSMISSION             EQUALIZATION       PAYMENTS      ARE      NOT

11          RECOVERABLE IN THIS RATE CASE, IN PART, BECAUSE THE

12          PROJECTED EQUALIZABLE INVESTMENTS ARE UNCERTAIN.                     DO

13          YOU AGREE?

14   A.     No. The six projects I identified above represent more than 76% of the

15          Total Investment providing the basis for ETI’s proposed transmission

16          equalization payments. Each of these projects has received full funding

17          approval and has either been constructed or is on schedule to be

18          constructed before the end of the rate year. Moreover, these projects

19          have resulted from a detailed and lengthy planning process that has

20          demonstrated the need for these projects such that they were included in

21          Entergy’s Transmission Construction Plan.




                                                                                   5
     Entergy Texas, Inc.                                                     Page 4 of 12
     Rebuttal Testimony of Mark F. McCulla
     Docket No. 39896


 1   Q.     YOU MENTIONED A DETAILED AND LENGTHY PLANNING PROCESS

 2          THAT DEVELOPED THESE PROJECTS.                 CAN YOU EXPLAIN THIS

 3          PROCESS?

 4   A.     Transmission facilities such as lines and substations are built as a result

 5          of an ongoing extensive planning process intended to ensure the Entergy

 6          Transmission System’s continued reliable operation in accordance with

 7          industry reliability standards, and to meet all firm load requirements,

 8          including serving the loads of the Operating Companies' retail customers.

 9          As such, the Entergy Transmission System is planned considering

10          expected load growth and long-term firm transmission service obligations

11          over a ten-year horizon. This planning process occurs annually to ensure

12          that any changes to the Entergy Transmission System are analyzed in a

13          timely manner.

14                  Entergy’s transmission planning group uses computer models to

15          assess the adequacy and reliability of the Entergy Transmission System.

16          The computer models used in this planning process include the

17          transmission system topology (the configuration of transmission lines,

18          substations, and other assets), forecasted load growth, available

19          generating resources, and planned changes to the electric grid. If the

20          planning studies indicate a projected reliability deficiency (e.g., facility

21          overload or undervoltage condition), projects are identified to address the

22          deficiency.    Once projects are identified, they are considered and, if

23          necessary, further refined by the project management and construction



                                                                                       6
     Entergy Texas, Inc.                                                                    Page 5 of 12
     Rebuttal Testimony of Mark F. McCulla
     Docket No. 39896


 1            group to ensure the most cost-effective and feasible solution is identified

 2            and included in Entergy’s Transmission Construction Plan.

 3

 4   Q.       IS ENTERGY’S TRANSMISSION CONSTRUCTION PLAN DEVELOPED

 5            WITH THE INPUT OF THE INDEPENDENT COORDINATOR OF

 6            TRANSMISSION (“ICT”) AND STAKEHOLDERS?

 7   A.       Yes. The Construction Plan is developed with input from the ICT1 and

 8            various stakeholders, such as retail regulators of the Entergy Operating

 9            Companies (including the Public Utility Commission of Texas) through the

10            Entergy Regional State Committee (“E-RSC”). Prior to the finalization of

11            the Entergy Construction Plan, Entergy presents its draft Construction

12            Plan at various stakeholder forums including the annual Transmission

13            Planning Summit, and solicits input from stakeholders and the ICT.

14            Moreover, the ICT provides input to the Entergy Construction Plan through
                                                       2
15            its development of the Base Plan.




     1
          Southwest Power Pool currently serves as the ICT for the Entergy Transmission System.
     2
          Per Attachment T to the Entergy OATT, the ICT develops the Base Plan used for cost
          allocation. The Base Plan includes projects necessary to meet transmission reliability criteria,
          and for which construction is to be initiated within the next five years.




                                                                                                        7
     Entergy Texas, Inc.                                                    Page 6 of 12
     Rebuttal Testimony of Mark F. McCulla
     Docket No. 39896


 1   Q.     WHAT       OCCURS       AFTER A   PROJECT IS INCLUDED IN THE

 2          CONSTRUCTION PLAN?

 3   A.     Projects in the Construction Plan must be approved for funding prior to the

 4          start of construction. After funding is approved, the project construction

 5          process begins, including project design, material procurement, right-of-

 6          way procurement, and actual construction.      The construction duration

 7          varies depending on the complexity and size of the project, but typically

 8          lasts between three and five years, with some projects finishing earlier

 9          based on extenuating circumstances.        For example, the Loblolly to

10          Hammond 230 kV line project took approximately three years to construct

11          after funding was approved. This project required new transmission right-

12          of-way.     By comparison, the construction of the Entergy Gulf States

13          Louisiana, L.L.C. (“EGSL”) Nelson to Moss Bluff 230 kV project is

14          projected to take approximately one year because EGSL owns the right-

15          of-way.

16

17   Q.     DO     THE     TOTAL      INVESTMENT    COSTS     INCLUDED      IN   ETI’S

18          PROPOSED             TRANSMISSION       EQUALIZATION          PAYMENTS

19          REPRESENT A REASONABLE FIGURE?

20   A.     Yes, as part of the project planning process, a budget is developed by the

21          project management team based on an analysis of all costs associated

22          with the project. This budget is then used to develop the Total Investment

23          figures that are used to project the Operating Companies’ transmission



                                                                                      8
     Entergy Texas, Inc.                                                      Page 7 of 12
     Rebuttal Testimony of Mark F. McCulla
     Docket No. 39896


 1          equalizable payment.             The Hammond-Loblolly 230 kV line project

 2          provides an opportunity to evaluate the reasonableness of these budget

 3          estimates because it has already been put in service. For the proposed

 4          transmission equalization payments, this project represented $39.9 million

 5          of the projected Total Investment. To date, more than $45.3 million has

 6          been charged to this project.

 7

 8   Q.     DR. GOINS ASSERTS (PAGE 20) THAT THE PROPOSED MSS-2

 9          COSTS SHOULD NOT BE RECOVERED IN THIS RATE CASE, IN

10          PART, BECAUSE THE PROPOSED ITC SPIN/MERGE TRANSACTION

11          WAS NOT INCLUDED IN THE ANALYSIS. DO YOU AGREE?

12   A.     No. As stated above, the proposed transmission equalization costs for

13          ETI are based on projected investments for the period of June 2012

14          through May 2013.         There is no proceeding seeking approval of the

15          transaction with ITC pending before the PUCT or any other regulator that

16          suggests ETI would not make transmission investments or not be subject

17          to Service Schedule MSS-2 transmission equalization during that time

18          period. Thus, it is not known that the ITC transaction would have any

19          effect on the period at issue. Further, Dr. Goins has failed to recognize all

20          the attendant impacts that would result even if such a change were to

21          occur prior to the end of the rate year.         When ETI no longer owns

22          transmission assets and is no longer subject to Service Schedule MSS-2

23          transmission equalization, ETI will still incur transmission costs for another



                                                                                        9
     Entergy Texas, Inc.                                                    Page 8 of 12
     Rebuttal Testimony of Mark F. McCulla
     Docket No. 39896


 1          type (i.e., costs for transmission service provided by ITC transmission

 2          assets). Dr. Goins has failed to measure the full net effect of one type of

 3          transmission cost substituting for another. For these reasons, Dr. Goins

 4          has not demonstrated (and cannot demonstrate) that either (1) the ITC

 5          transaction presents a known and measureable change that can be

 6          accounted for in this proceeding or (2) he has properly accounted for all

 7          attendant impacts that would result from that change in transmission

 8          cost incurrence.

 9

10                               III.    AFFILIATE EXPENSES

11   Q.     ON PAGE 75 OF HER DIRECT TESTIMONY, DR. SZERSZEN

12          ASSERTS THAT $42,698 SHOULD BE REMOVED FROM THE

13          AFFILIATE EXPENSES BECAUSE THE COST OF PROVIDING RENTAL

14          SPACE ON TRANSMISSION POLES EXCEEDS THE REVENUE

15          RECEIVED FROM PROVIDING THAT RENTAL SPACE.                       DO YOU

16          AGREE?

17   A.     No.

18

19   Q.     WHY NOT?

20   A.     Dr. Szerszen’s assertion is misplaced because she has confused the

21          rental of space on transmission poles and the rental of space on

22          distribution poles. In doing so, she has performed a cost-benefit analysis

23          that erroneously compares the cost of providing rental space on



                                                                                     10
     Entergy Texas, Inc.                                                    Page 9 of 12
     Rebuttal Testimony of Mark F. McCulla
     Docket No. 39896


 1          distribution poles with the income received solely from rental of space on

 2          transmission poles.

 3

 4   Q.     IN PERFORMING HER COST-BENEFIT ANALYSIS, WHAT FIGURES

 5          DID DR. SZERSZEN USE FOR THE COST OF PROVIDING RENTAL

 6          SPACE ON POLES?

 7   A.     Dr. Szerszen states that “ETI was allocated $57,288 for costs associated

 8          with the rental of space on Entergy transmission poles and direct charged

 9          $9,886 for the same activities, including the costs of pole rental contract

10          administration.” In support of these figures, she cites two project codes –

11          P3PCTJTUSE and F3PCTJUSE.           I was unable to locate project code

12          F3PCTJUSE, but I did identify the two project codes associated with pole

13          rentals. These two project codes included total charges that match the

14          monetary amounts cited by Dr. Szerszen – F3PCTJGUSE ($9,886) and

15          F3PCTJTUSE ($57,288). I therefore assume that Dr. Szerszen relied on

16          these two project codes in determining the expenses associated with pole

17          rentals and that she meant to cite these two project codes in support of

18          her testimony.




                                                                                     11
     Entergy Texas, Inc.                                                     Page 10 of 12
     Rebuttal Testimony of Mark F. McCulla
     Docket No. 39896


 1   Q.     DO THESE PROJECT CODES CAPTURE THE COSTS ASSOCIATED

 2          WITH THE RENTAL OF SPACE ON ENTERGY TRANSMISSION

 3          POLES, AS DR. SZERSZEN SUGGESTS?

 4   A.     No, a review of pages 743 and 744 of Exhibit SBT-E attached to the

 5          Direct Testimony of ETI witness Stephanie Tuminello shows that neither

 6          of these project codes includes any expenses from the transmission

 7          function. Indeed, Exhibit SBT-E shows that the only two functions that

 8          charged to these project codes were Distribution Operations and Human

 9          Resources, with the vast majority of charges coming from the Distribution

10          Operations function. This means that these project codes have captured

11          the costs of administering rental space on distribution poles. At the very

12          least, it appears clear that these project codes do not capture solely the

13          cost of administering rental space on transmission poles.

14

15   Q.     IN PERFORMING HER COST-BENEFIT ANALYSIS, WHAT FIGURE DID

16          DR. SZERSZEN USE FOR THE REVENUES RECEIVED FROM

17          RENTAL SPACE ON POLES?

18   A.     For the revenues used in her cost-benefit analysis, Dr. Szerszen relies

19          solely on a response to the Commission Staff’s request for information 1-

20          11 (“Staff 1-11”), which I sponsored. The request asked for “any utility

21          revenues from affiliates or third-parties for the use of the transmission

22          facilities for any type of communication system (cell, Internet, cable).” ETI

23          responded that the revenues “for the use of the transmission facilities for



                                                                                       12
     Entergy Texas, Inc.                                                   Page 11 of 12
     Rebuttal Testimony of Mark F. McCulla
     Docket No. 39896


 1          any type of communication system totaled $24,476.30 for the test period.”

 2          As stated in both the request and the response, the $24,476.30 in

 3          revenue related solely to the rental of space on transmission poles. This

 4          amount does not capture any of the revenues ETI received for the rental

 5          of distribution poles.

 6

 7   Q.     HAS ETI RECEIVED ADDITIONAL REVENUE FOR THE RENTAL OF

 8          DISTRIBUTION POLES?

 9   A.     Yes. ETI reports the rental income it receives from the use of its electric

10          property in FERC Account 454, which includes Rent from Electric Property

11          (Account 454000) and Rent from Pole Attachments-Distribution Lines

12          (Account 454100). The $24,476.30 identified in response to Staff 1-11 is

13          recorded in Account 454000 as Rent from Electric Property. The revenue

14          received from the rental of distribution poles, however, is recorded in

15          Account 454100 as Rent from Pole Attachments-Distribution Lines.

16                  The recording of this rental income from distribution poles in FERC

17          Account 454100 was also identified by the Company in response to a

18          request for information from the Office of Public Utility Counsel in the

19          2009 ETI Rate Case (Docket No. 37744). That response, which I have

20          attached as Exhibit MFM-R-2, stated that ETI recovered $2,434,411 in

21          revenue from the rental of distribution poles during that test year. In the

22          test year for this rate case, the Company’s revenue from the rental of

23          distribution poles was $2,503,116, as identified in Schedule P (Cost of



                                                                                     13
     Entergy Texas, Inc.                                                 Page 12 of 12
     Rebuttal Testimony of Mark F. McCulla
     Docket No. 39896


 1          Service work papers at Bates-numbered pages SCHED_COS_WP_6-108

 2          to 6-111).

 3

 4   Q.     AFTER REVIEWING THE ACTUAL EXPENSES AND REVENUES

 5          ASSOCIATED WITH POLE RENTALS, WHAT IS YOUR CONCLUSION

 6          REGARDING DR. SERZEN’S ASSERTION THAT $42,698 SHOULD BE

 7          REMOVED FROM AFFILIATE EXPENSES?

 8   A.     By failing to account for revenue ETI received from the rental of

 9          distribution poles, Dr. Szerszen has incorrectly assumed that ETI did not

10          receive sufficient revenue to cover the administrative cost of providing

11          those distribution pole rentals.    Because ETI has received more than

12          $2.5 million in revenue associated with distribution pole rentals, while

13          incurring $67,174 in expenses for pole rentals, Dr. Szerszen’s proposed

14          disallowance is inappropriate.

15

16                                    IV.    CONCLUSION

17   Q.     DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY?

18   A.     Yes.




                                                                                   14
                               Projects Included in MSS-2 Projections for June 2012 – May 2013

                     Project                  Estimated       Funding                  Construction Status
                                                Total          Status
                                             Investment
                                              ($million)
     1 Loblolly to Hammond 230 kV line          $39.9        Approved     In service on December 16, 2011
     2 Acadiana Area Improvement                $25.3        Approved     500 kV position for Cleco autotransformer
       Project Phase 2: Labbe to Sellers                                  completed on March 19, 2012. Construction has
       Road 230 kV line and 500 kV                                        begun on final 20 structures for Labbe to Sellers
       position for Cleco autotransformer                                 Road line with projected in-service date of June
                                                                          29, 2012
     3 Southeast Louisiana Coastal              $23.1        Approved     In the design/construction phase; projected in-
       Improvement Plan Phase 3:                                          service date of December 31, 2012
       Oakville-Alliance 230 kV line and
       230-114 kV autotransformer at
       Alliance substation
     4 Tillatoba to South Grenada 230 kV        $20.6        Approved     Under construction; projected in-service date of
       line                                                               June 1, 2012
     5 Southeast Louisiana Coastal              $18.5        Approved     In the design/construction phase; projected in-
       Improvement Plan Phase 2: Build                                    service date of September 20, 2012
       Peters Road-Oakville 230 kV line
       and substation
     6 Nelson to Moss Bluff 230 kV Line         $13.6        Approved     Under construction; projected in-service date of
                                                                          May 31, 2012
                                                 $141




15
                                                                                                                              Docket No. 39896
                                                                                                                                    Page 1 of 1
                                                                                                                               Exhibit MFM-R-1
                                                                              Exhibit MFM-R-2
                                                                             Docket No. 39896
                            ENTERGY TEXAS, INC.                                    Page 1 of 3
                    PUBLIC UTILITY COMMISSION OF TEXAS
                      Docket No. 37744 - 2009 ETI Rate Case

Response of: Entergy Texas, Inc.                 Prepared By: Joe Bennett
to the Sixth Set of Data Requests                Sponsoring Witness: Shawn B. Corkran
of Requesting Party: Office of Public Utility    Beginning Sequence No.
Counsel
                                                 Ending Sequence No.

Question No.: OPUC 6-5                          Part No.:               Addendum:

Question:

       a.     Please provide all ETI test year rental income associated with the third
              party contracts discussed in project F3PCTJGUSC.

       b.     Where is rental income included in the RFP?

       c.     Provide all documentation supporting your response to (b) above.


Response:

Note: This response assumes that the question intended to refer to Project Codes
F3PCTJGUSE and F3PCTJTUSE. Project Code F3PCTJGUSC does not exist.

   a. The services provided under Project Codes F3PCTJGUSE and F3PCTJTUSE are
      associated with pole attachment rentals. The rental income for pole attachments
      during the test year was recorded in FERC Account 454 in the amount of
      $2,434,411.

   b. See Schedule P, Cost of Service WPs (Vol. 1of 3), Volume Sched-WP_6, Bates
      pages SCHED_COS_WP_6-143 to 6-146.

   c. See the Company’s response to subpart (b) above.




                                                                                           16
  37744                                                                    OPUC 6-5 LR5304
                                                                                                                                                                                                      Exhibit MFM-R-2
                                                                                                                                                                                                     Docket No. 39896
                                                                                                                                                                                                           Page 2 of 3

ENTITY      COMPANY_NAME          CONTRACT_ID CONTRACT_DESC      REFERENCE_NUM       BILLING_DT               BILLING PERIODS               AMOUNT_BILLED      AMT PAID      FREQUENCY   BILL_TYPE   INVOICE #   RESP_COORDINATOR
ETI      ALMEGA CABLE                 10117   ANNUAL POLE REN100006683           3/10/2009 09:19:46    Jan. 1, 2009 through Dec. 31, 2009         37054.41                     Annual      Rental     9602740         chutche
ETI      ALMEGA CABLE                 10117   ANNUAL POLE REN100007642           1/21/2010 15:35:02    Jan 1, 2010 through Dec. 31, 2010          29359.67                     Annual      Rental     9603053         chutche
ETI      BRIGHTER CABLE COMMU         10116   ANNUAL POLE REN100006682           3/10/2009 09:18:10    Jan. 1, 2009 through Dec. 31, 2009            769.54        769.54      Annual      Rental     9602739         chutche
ETI      BRIGHTER CABLE COMMU         10116   ANNUAL POLE REN100007551           1/19/2010 10:30:58    Jan 1, 2010 through Dec. 31, 2010             756.46                    Annual      Rental     9603052         chutche
ETI      Cable One                      21    ANNUAL POLE REN100000087           2/20/2001 15:14:31    Jan. 1, 2001 through Dec. 31, 2001            335.35        335.35      Annual      Rental     1059771         rpascua
ETI      Cable Texas, Inc               23    ANNUAL POLE REN100000075           2/15/2001 13:52:04    Jan. 1, 2001 through Dec. 31, 2001         29620.23       29620.23      Annual      Rental     1059468         rpascua
ETI      Carrell Communications       10084   ANNUAL POLE REN100003857           9/7/2006 14:58:50     Jan. 1, 2006 through Dec. 31, 2006         46345.37                     Annual      Rental     9601887         chutche
ETI      Carrell Communications       10084   ANNUAL POLE REN100004197           1/18/2007 07:46:04    Jan. 1, 2007 through Dec. 31, 2007         46345.37                     Annual      Rental     9601956         chutche
ETI      Carrell Communications       10084   ANNUAL POLE REN100005098           1/15/2008 14:51:56    Jan. 1, 2008 through Dec. 31, 2008         46345.37                     Annual      Rental     9602260         chutche
ETI      Classic Cable                  33    POLE RENTAL -DBA100000077          2/15/2001 13:56:21    Jan. 1, 2001 through Dec. 31, 2001            804.84        804.84      Annual      Rental     1059469         chutche
ETI      Classic Cable                10042   POLE RENTAL - DB 100000287         7/26/2001 06:43:04    Jul.1, 2000 through Dec. 31, 2000          20043.34       20043.34      Annual      Rental     1066278         chutche
ETI      Classic Cable                10042   POLE RENTAL - DB 100000386         12/6/2001 16:47:52    Jan. 1, 2001 through Dec. 31, 2001         20043.34       20043.34      Annual      Rental     1072853         chutche
ETI      Classic Cable                10042   POLE RENTAL - DB 100000493         1/16/2002 09:17:06    Jan. 1, 2002 through Dec. 31, 2002         20043.34       20043.34      Annual      Rental     1075141         chutche
ETI      Classic Cable                  33    POLE RENTAL -DBA100000494          1/16/2002 09:19:27    Jan. 1, 2002 through Dec. 31, 2002           1885.02       1885.02      Annual      Rental     1075125         chutche
ETI      Classic Cable                  33    POLE RENTAL -DBA100000726          1/13/2003 08:24:01    Jan. 1, 2003 through Dec. 31, 2003           1885.02       1885.02      Annual      Rental     1092919         chutche
ETI      Classic Cable                10042   POLE RENTAL - DB 100000740         1/13/2003 14:11:09    Jan. 1, 2003 through Dec. 31, 2003         20043.34       20043.34      Annual      Rental     1092949         chutche
ETI      Classic Cable                10042   POLE RENTAL - DB 100001557         1/28/2004 10:59:26    Jan. 1, 2004 through Dec. 31, 2004         20964.67       20964.67      Annual      Rental     9601144         chutche
ETI      Classic Cable                  33    POLE RENTAL -DBA100001558          1/28/2004 11:00:23    Jan. 1, 2004 through Dec. 31, 2004           1885.02       1885.02      Annual      Rental     9601130         chutche
ETI      Classic Cable                  33    POLE RENTAL -DBA100002377          1/13/2005 07:22:25    Jan. 1, 2005 through Dec. 31, 2005           1885.02       1885.02      Annual      Rental     9601347         chutche
ETI      Classic Cable                10042   POLE RENTAL - DB 100002378         1/13/2005 07:23:58    Jan. 1, 2005 through Dec. 31, 2005         20964.67       20964.67      Annual      Rental     9601361         chutche
ETI      Classic Cable                  33    POLE RENTAL -DBA100003197          1/11/2006 07:28:59    Jan. 1, 2006 through Dec. 31, 2006           1885.02       1885.02      Annual      Rental     9601633         chutche
ETI      Classic Cable                10042   POLE RENTAL - DB 100003198         1/11/2006 07:31:09    Jan. 1, 2006 through Dec. 31, 2006         20964.67       20964.67      Annual      Rental     9601647         chutche
ETI      Classic Cable                  33    POLE RENTAL -DBA100004697          7/18/2007 09:30:25    Jan. 1, 2007 through Dec. 31, 2007           7084.71       7084.71      Annual      Rental     9602179         chutche
ETI      Classic Cable                10042   POLE RENTAL - DB 100004699         7/18/2007 09:35:14    Jan. 1, 2007 through Dec. 31, 2007           3805.34       3805.34      Annual      Rental     9602183         chutche
ETI      Classic Cable                10042   POLE RENTAL - DB 100005099         1/15/2008 14:54:48    Jan. 1, 2008 through Dec. 31, 2008           3805.34       3805.34      Annual      Rental     9602254         chutche
ETI      Classic Cable                  33    POLE RENTAL -DBA100005100          1/15/2008 14:56:13    Jan. 1, 2008 through Dec. 31, 2008           7084.71       7084.71      Annual      Rental     9602240         chutche
ETI      Classic Cable                  33    POLE RENTAL -DBA100006477          2/6/2009 13:57:21     Jan. 1, 2009 through Dec. 31, 2009           7084.71       7084.71      Annual      Rental     9602693         chutche
ETI      Classic Cable                10042   POLE RENTAL - DB 100006490         2/6/2009 14:17:15     Jan. 1, 2009 through Dec. 31, 2009              4236         4236       Annual      Rental     9602705         chutche
ETI      Classic Cable                  33    POLE RENTAL -DBA100007537          1/19/2010 10:13:22    Jan 1, 2010 through Dec. 31, 2010            6964.29       6964.29      Annual      Rental     9603031         chutche
ETI      Classic Cable                10042   POLE RENTAL - DB 100007546         1/19/2010 10:26:34    Jan 1, 2010 through Dec. 31, 2010                4164         4164      Annual      Rental     9603044         chutche
ETI      Comcast Cable Communcat      10112   ANNUAL POLE REN100006678           3/10/2009 09:14:22    Jan. 1, 2009 through Dec. 31, 2009         13947.03       13947.03      Annual      Rental     9602735         chutche
ETI      Comcast Cable Communcat      10112   ANNUAL POLE REN100007550           1/19/2010 10:29:58    Jan 1, 2010 through Dec. 31, 2010          13709.97                     Annual      Rental     9603049         chutche
ETI      DAYBREAK COMMUNICAT          10115   ANNUAL POLE REN100006681           3/10/2009 09:17:18    Jan. 1, 2009 through Dec. 31, 2009          11243.05                    Annual      Rental     9602738         chutche
ETI      DAYBREAK COMMUNICAT          10115   ANNUAL POLE REN100007641           1/21/2010 15:34:19    Jan 1, 2010 through Dec. 31, 2010           11051.95                    Annual      Rental     9603051         chutche
ETI      Etan Industries, Inc           49    ANNUAL POLE REN100000083           2/15/2001 15:09:23    Jan. 1, 2001 through Dec. 31, 2001         12937.45       12937.45      Annual      Rental     1059470         chutche
ETI      Etan Industries, Inc           49    ANNUAL POLE REN100000735           1/13/2003 08:47:33    Jan. 1, 2003 through Dec. 31, 2003           4077.15        4077.15     Annual      Rental     1093102         chutche
ETI      Etan Industries, Inc           49    ANNUAL POLE REN100001559           1/28/2004 11:01:12    Jan. 1, 2004 through Dec. 31, 2004           6576.39        6576.39     Annual      Rental     9601131         chutche
ETI      Etan Industries, Inc           49    ANNUAL POLE REN100002338           1/11/2005 07:34:22    Jan. 1, 2005 through Dec. 31, 2005           6576.39        6576.39     Annual      Rental     9601348         chutche
ETI      Etan Industries, Inc           49    ANNUAL POLE REN100003199           1/11/2006 07:34:33    Jan. 1, 2006 through Dec. 31, 2006           6576.39        6576.39     Annual      Rental     9601634         chutche
ETI      Etan Industries, Inc           49    ANNUAL POLE REN100004200           1/18/2007 07:52:35    Jan. 1, 2007 through Dec. 31, 2007           6576.39        6576.39     Annual      Rental     9601937         chutche
ETI      Etan Industries, Inc           49    ANNUAL POLE REN100005101           1/15/2008 14:58:45    Jan. 1, 2008 through Dec. 31, 2008           6576.39        6576.39     Annual      Rental     9602241         chutche
ETI      Etan Industries, Inc           49    ANNUAL POLE REN100006478           2/6/2009 14:01:50     Jan. 1, 2009 through Dec. 31, 2009           6576.39        6576.39     Annual      Rental     9602694         chutche
ETI      Etan Industries, Inc           49    ANNUAL POLE REN100007538           1/19/2010 10:15:12    Jan 1, 2010 through Dec. 31, 2010            6464.61        6464.61     Annual      Rental     9603032         chutche
ETI      Friendship Cable of TX         57     POLE RENTAL - DB100000074         2/15/2001 13:39:58    Jan. 1, 2001 through Dec. 31, 2001        145658.39      145658.39      Annual      Rental     1059471         chutche
ETI      Friendship Cable of TX         57     POLE RENTAL - DB100000495         1/16/2002 09:25:17    Jan. 1, 2002 through Dec. 31, 2002        146784.46      146784.46      Annual      Rental     1075127         chutche
ETI      Friendship Cable of TX         57     POLE RENTAL - DB100000725         1/13/2003 08:18:56    Jul. 1, 2003 through Dec. 31, 2003        146784.46      146784.46      Annual      Rental     1092922         chutche
ETI      Friendship Cable of TX         57     POLE RENTAL - DB100001560         1/28/2004 11:01:56    Jan. 1, 2004 through Dec. 31, 2004        146787.99      146787.99      Annual      Rental     9601132         chutche
ETI      Friendship Cable of TX         57     POLE RENTAL - DB100002379         1/13/2005 07:25:04    Jan. 1, 2005 through Dec. 31, 2005        146787.99      141690.08      Annual      Rental     9601349         chutche
ETI      Friendship Cable of TX         57     POLE RENTAL - DB100004698         7/18/2007 09:33:11    Jan. 1, 2007 through Dec. 31, 2007          15027.21       15027.21     Annual      Rental     9602180         chutche
ETI      Friendship Cable of TX         57     POLE RENTAL - DB100005102         1/15/2008 15:00:02    Jan. 1, 2008 through Dec. 31, 2008          15027.21       15027.21     Annual      Rental     9602242         chutche
ETI      Friendship Cable of TX         57     POLE RENTAL - DB100006479         2/6/2009 14:02:55     Jan. 1, 2009 through Dec. 31, 2009         13685.22       13685.22      Annual      Rental     9602695         chutche
ETI      Friendship Cable of TX         57     POLE RENTAL - DB100007637         1/21/2010 15:28:03    Jan 1, 2010 through Dec. 31, 2010          16090.39       16090.39      Annual      Rental     9603033         chutche
ETI      Galaxy Cablevision LP          59    POLE RENTAL      100000082         2/15/2001 14:37:58    Jan. 1, 2001 through Dec. 31, 2001           5708.01        5708.01     Annual      Rental     1059472         chutche
ETI      Galaxy Cablevision LP          59    POLE RENTAL      100000731         1/13/2003 08:39:46    Jan. 1, 2003 through Dec. 31, 2003            6989.4         6989.4     Annual      Rental     1092923         chutche
ETI      Galaxy Cablevision LP          59    POLE RENTAL      100001561         1/28/2004 11:02:42    Jan. 1, 2004 through Dec. 31, 2004           6872.91        6872.91     Annual      Rental     9601133         chutche
ETI      Galaxy Cablevision LP          59    POLE RENTAL      100002382         1/13/2005 07:30:06    Jan. 1, 2005 through Dec. 31, 2005           6872.91        6872.91     Annual      Rental     9601350         chutche
ETI      Galaxy Cablevision LP          59    POLE RENTAL      100003201         1/11/2006 07:38:06    Jan. 1, 2006 through Dec. 31, 2006           6872.91        6872.91     Annual      Rental     9601636         chutche
ETI      Galaxy Cablevision LP          59    POLE RENTAL      100004202         1/18/2007 07:55:42    Jan. 1, 2007 through Dec. 31, 2007           6872.91        6872.91     Annual      Rental     9601939         chutche
ETI      Galaxy Cablevision LP          59    POLE RENTAL      100005103         1/15/2008 15:03:52    Jan. 1, 2008 through Dec. 31, 2008           6872.91        6872.91     Annual      Rental     9602243         chutche
ETI      Galaxy Cablevision LP          59    POLE RENTAL      100006697         3/11/2009 08:47:16    Jan. 1, 2009 through Dec. 31, 2009           6209.27        6209.27     Annual      Rental     9602741         chutche
ETI      Galaxy Cablevision LP          59    POLE RENTAL      100007539         1/19/2010 10:16:18    Jan 1, 2010 through Dec. 31, 2010            6103.73        6103.73     Annual      Rental     9603034         chutche
ETI      Lakewood Cablevision           78     POLE RENTAL - DB100000078         2/15/2001 13:59:32    Jan. 1, 2001 through Dec. 31, 2001          11288.94       11288.94     Annual      Rental     1059473         chutche
ETI      Lakewood Cablevision           78     POLE RENTAL - DB100000497         1/16/2002 09:31:35    Jan. 1, 2002 through Dec. 31, 2002          13791.71       13791.71     Annual      Rental     1075129         chutche
ETI      Lakewood Cablevision           78     POLE RENTAL - DB100000727         1/13/2003 08:27:51    Jan. 1, 2003 through Dec. 31, 2003          13791.71       13791.71     Annual      Rental     1092924         chutche
ETI      Lakewood Cablevision           78     POLE RENTAL - DB100001562         1/28/2004 11:03:22    Jan. 1, 2004 through Dec. 31, 2004          13791.71       13791.71     Annual      Rental     9601134         chutche
ETI      Lakewood Cablevision           78     POLE RENTAL - DB100002380         1/13/2005 07:26:22    Jan. 1, 2005 through Dec. 31, 2005          15231.95       15231.95     Annual      Rental     9601351         chutche
ETI      Lakewood Cablevision           78     POLE RENTAL - DB100003202         1/11/2006 07:39:04    Jan. 1, 2006 through Dec. 31, 2006          15281.37       15281.37     Annual      Rental     9601637         chutche
ETI      Lakewood Cablevision           78     POLE RENTAL - DB100004701         7/18/2007 10:41:59    Jan. 1, 2007 through Dec. 31, 2007           9047.39        9047.39     Annual      Rental     9602181         chutche
ETI      Lakewood Cablevision           78     POLE RENTAL - DB100005104         1/15/2008 15:04:59    Jan. 1, 2008 through Dec. 31, 2008           9047.39        9047.39     Annual      Rental     9602244         chutche
ETI      Lakewood Cablevision           78     POLE RENTAL - DB100006480         2/6/2009 14:05:40     Jan. 1, 2009 through Dec. 31, 2009           9047.39        9047.39     Annual      Rental     9602696         chutche
ETI      Lakewood Cablevision           78     POLE RENTAL - DB100007757         2/2/2010 21:28:05     Jan 1, 2010 through Dec. 31, 2010            8893.61        8893.61     Annual      Rental     9603035         chutche
ETI      North Texas Cablecomm          89    ANNUAL POLE REN100000091           2/20/2001 15:33:10    Jan. 1, 2001 through Dec. 31, 2001           3155.82        3155.82     Annual      Rental     1059688         chutche
ETI      North Texas Cablecomm          89    ANNUAL POLE REN100000733           1/13/2003 08:43:18    Jan. 1, 2003 through Dec. 31, 2003           3879.47        3879.47     Annual      Rental     1092926         chutche
ETI      North Texas Cablecomm          89    ANNUAL POLE REN100001563           1/28/2004 11:04:03    Jan. 1, 2004 through Dec. 31, 2004             914.27        914.27     Annual      Rental     9601135         chutche
ETI      North Texas Cablecomm          89    ANNUAL POLE REN100002326           1/10/2005 10:40:20    Jan. 1, 2005 through Dec. 31, 2005             914.27        914.27     Annual      Rental     9601352         chutche
ETI      North Texas Cablecomm          89    ANNUAL POLE REN100003203           1/11/2006 07:40:05    Jan. 1, 2006 through Dec. 31, 2006             914.27        914.27     Annual      Rental     9601638         chutche
ETI      North Texas Cablecomm          89    ANNUAL POLE REN100004204           1/18/2007 07:58:03    Jan. 1, 2007 through Dec. 31, 2007             914.27                   Annual      Rental     9601941         chutche
ETI      North Texas Cablecomm          89    ANNUAL POLE REN100005105           1/15/2008 15:07:28    Jan. 1, 2008 through Dec. 31, 2008             914.27                   Annual      Rental     9602245         chutche
ETI      Northland Cable Properties    489    ANNUAL POLE REN100000080           2/15/2001 14:28:12    Jan. 1, 2001 through Dec. 31, 2001         42476.49       42476.49      Annual      Rental     1059480         chutche
ETI      Northland Cable Properties    489    ANNUAL POLE REN100000498           1/16/2002 09:37:28    Jan. 1, 2002 through Dec. 31, 2002         44915.72       44915.72      Annual      Rental     1075140         chutche
ETI      Northland Cable Properties    489    ANNUAL POLE REN100000732           1/13/2003 08:41:14    Jan. 1, 2003 through Dec. 31, 2003         44915.72       44915.72      Annual      Rental     1092948         chutche
ETI      Northland Cable Properties    489    ANNUAL POLE REN100001758           6/29/2004 09:29:49    Jan. 1, 2004 through Dec. 31, 2004         44413.84       44413.84      Annual      Rental     9601203         chutche
ETI      Northland Cable Properties    489    ANNUAL POLE REN100002577           3/7/2005 08:55:44     Jan. 1, 2005 through Dec. 31, 2005         44428.58       44428.58      Annual      Rental     9601496         chutche
ETI      Northland Cable Properties    489    ANNUAL POLE REN100002837           6/6/2005 15:04:40       Back billing 2000 through 2001                39.12        39.12      Annual      Rental     9601513         chutche
ETI      Northland Cable Properties    489    ANNUAL POLE REN100003204           1/11/2006 07:45:00    Jan. 1, 2006 through Dec. 31, 2006         44524.18       44524.18      Annual      Rental     9601646         chutche
ETI      Northland Cable Properties    489    ANNUAL POLE REN100004205           1/18/2007 08:00:31    Jan. 1, 2007 through Dec. 31, 2007         44524.18       44485.06      Annual      Rental     9601949         chutche
ETI      Northland Cable Properties    489    ANNUAL POLE REN100005106           1/15/2008 15:08:45    Jan. 1, 2008 through Dec. 31, 2008         44541.54       44541.54      Annual      Rental     9602253         chutche
ETI      Northland Cable Properties    489    ANNUAL POLE REN100006757           4/7/2009 15:24:11     Jan. 1, 2009 through Dec. 31, 2009         41293.06       41293.06      Annual      Rental     9602746         chutche
ETI      Northland Cable Properties    489    ANNUAL POLE REN100007638           1/21/2010 15:30:16    Jan 1, 2010 through Dec. 31, 2010          39526.77                     Annual      Rental     9603043         chutche
ETI      Northland Cable Properties    489    ANNUAL POLE REN1029506             10/15/1998 00:00:00   Jul. 1, 1998 through Dec. 31, 1998         14525.95       14525.95      Annual      Rental     1029506         chutche
ETI      Northland Cable Television     93    ANNUAL POLE REN100000081           2/15/2001 14:29:26    Jan. 1, 2001 through Dec. 31, 2001         12033.77       12033.77      Annual      Rental     1059474         chutche
ETI      Northland Cable Television     93    ANNUAL POLE REN100000499           1/16/2002 09:38:39    Jan. 1, 2002 through Dec. 31, 2002         12655.05       12655.05      Annual      Rental     1075131         chutche
ETI      Northland Cable Television     93    ANNUAL POLE REN100000737           1/13/2003 08:52:42    Jan. 1, 2003 through Dec. 31, 2003         12655.05       12655.05      Annual      Rental     1092927         chutche
ETI      Northland Cable Television     93    ANNUAL POLE REN100001565           1/28/2004 11:05:42    Jan. 1, 2004 through Dec. 31, 2004         12655.05       12655.05      Annual      Rental     9601136         chutche
ETI      Northland Cable Television     93    ANNUAL POLE REN100002317           1/10/2005 09:06:41    Jan. 1, 2005 through Dec. 31, 2005         12655.05       12655.05      Annual      Rental     9601353         chutche
ETI      Northland Cable Television     93    ANNUAL POLE REN100003205           1/11/2006 07:47:18    Jan. 1, 2006 through Dec. 31, 2006         12655.05       12655.05      Annual      Rental     9601639         chutche
ETI      Northland Cable Television     93    ANNUAL POLE REN100004700           7/18/2007 09:43:08    Jan. 1, 2007 through Dec. 31, 2007           5570.34       5570.34      Annual      Rental     9602182         chutche
ETI      Northland Cable Television     93    ANNUAL POLE REN100005097           1/15/2008 14:50:12    Jan. 1, 2008 through Dec. 31, 2008           5570.34       5570.34      Annual      Rental     9602246         chutche
ETI      Northland Cable Television     93    ANNUAL POLE REN100006481           2/6/2009 14:06:59     Jan. 1, 2009 through Dec. 31, 2009           6643.46       6643.46      Annual      Rental     9602697         chutche
ETI      Northland Cable Television     93    ANNUAL POLE REN100007540           1/19/2010 10:17:29    Jan 1, 2010 through Dec. 31, 2010            6530.54       6530.54      Annual      Rental     9603036         chutche
ETI      Oasis Communications LLC     10071   DBA JONES BROAD100001837           7/12/2004 11:25:12    Jan. 1, 2004 through Dec. 31, 2004             812.52       812.52      Annual      Rental     9601246         chutche
ETI      Oasis Communications LLC     10071   DBA JONES BROAD100002318           1/10/2005 09:11:04    Jan. 1, 2005 through Dec. 31, 2005             812.52       812.52      Annual      Rental     9601366         chutche
ETI      Oasis Communications LLC     10071   DBA JONES BROAD100003206           1/11/2006 07:49:01    Jan. 1, 2006 through Dec. 31, 2006             812.52       812.52      Annual      Rental     9601652         chutche
ETI      Oasis Communications LLC     10071   DBA JONES BROAD100004207           1/18/2007 08:03:58    Jan. 1, 2007 through Dec. 31, 2007             812.52                   Annual      Rental     9601955         chutche
ETI      Oasis Communications LLC     10071   DBA JONES BROAD100005107           1/15/2008 15:09:50    Jan. 1, 2008 through Dec. 31, 2008             812.52                   Annual      Rental     9602259         chutche
ETI      Oasis Communications LLC     10071   DBA JONES BROAD100006618           2/20/2009 11:00:14    Jan. 1, 2009 through Dec. 31, 2009             991.93                   Annual      Rental     9602733         chutche
ETI      Oasis Communications LLC     10071   DBA JONES BROAD100007644           1/21/2010 15:37:56    Jan 1, 2010 through Dec. 31, 2010             975.07                    Annual      Rental     9603047         chutche
ETI      PC One/J. Feeney & Assoc     10109   ANNUAL POLE REN100006677           3/10/2009 09:12:13    Jan. 1, 2009 through Dec. 31, 2009            6113.96                   Annual      Rental     9602734         chutche
ETI      PC One/J. Feeney & Assoc     10109   ANNUAL POLE REN100007639           1/21/2010 15:31:37    Jan 1, 2010 through Dec. 31, 2010            6010.04                    Annual      Rental     9603048         chutche
ETI      Phonoscope, LTD              10061   ANNUAL POLE REN100000736           1/13/2003 08:51:17    Jan. 1, 2003 through Dec. 31, 2003              423.6        423.6      Annual      Rental     1092951         chutche
ETI      Phonoscope, LTD              10061   ANNUAL POLE REN100001566           1/28/2004 11:06:25    Jan. 1, 2004 through Dec. 31, 2004           3357.03       3357.03      Annual      Rental     9601147         chutche
ETI      Phonoscope, LTD              10061   ANNUAL POLE REN100002319           1/10/2005 09:13:47    Jan. 1, 2005 through Dec. 31, 2005           4539.58       4539.58      Annual      Rental     9601364         chutche
ETI      Phonoscope, LTD              10061   ANNUAL POLE REN100003207           1/11/2006 07:50:21    Jan. 1, 2006 through Dec. 31, 2006           6018.65       6018.65      Annual      Rental     9601650         chutche
ETI      Phonoscope, LTD              10061   ANNUAL POLE REN100004208           1/18/2007 08:05:00    Jan. 1, 2007 through Dec. 31, 2007           6053.95       6053.95      Annual      Rental     9601953         chutche
ETI      Phonoscope, LTD              10061   ANNUAL POLE REN100005108           1/15/2008 15:10:46    Jan. 1, 2008 through Dec. 31, 2008           6982.34       6982.34      Annual      Rental     9602257         chutche
ETI      Phonoscope, LTD              10061   ANNUAL POLE REN100006617           2/20/2009 10:58:12    Jan. 1, 2009 through Dec. 31, 2009           7698.93       7698.93      Annual      Rental     9602732         chutche




                                                                                                                                                                                                                                17
                       37744                                                                                                                                                                   OPUC 6-5 LR5305
                                                                                                                                                                                                           Exhibit MFM-R-2
                                                                                                                                                                                                          Docket No. 39896
                                                                                                                                                                                                                Page 3 of 3

ENTITY      COMPANY_NAME         CONTRACT_ID CONTRACT_DESC         REFERENCE_NUM       BILLING_DT                 BILLING PERIODS                AMOUNT_BILLED      AMT PAID      FREQUENCY   BILL_TYPE   INVOICE #   RESP_COORDINATOR
ETI      Phonoscope, LTD             10061   ANNUAL POLE REN100007549              1/19/2010 10:28:46      Jan 1, 2010 through Dec. 31, 2010             7658.29       7658.29      Annual      Rental     9603046         chutche
ETI      Rapid Acquisition Co LLC    10095   ANNUAL POLE REN100004702              7/18/2007 14:37:32      Jan. 1, 2007 through Dec. 31, 2007          77952.99                     Annual      Rental     9602184         chutche
ETI      Rapid Acquisition Co LLC    10095   ANNUAL POLE REN100005162              1/16/2008 13:58:55      Jan. 1, 2008 through Dec. 31, 2008          77952.99                     Annual      Rental     9602261         chutche
ETI      RB3 LLC & ARKLAOKTEX d      10113   ANNUAL POLE REN100006780              5/18/2009 14:31:48      Jan. 1, 2009 through Dec. 31, 2009            5580.93                    Annual      Rental     9602753         chutche
ETI      Reveille Broadband          10130   ANNUAL POLE REN100007552              1/19/2010 10:31:54      Jan 1, 2010 through Dec. 31, 2010              1741.94                   Annual      Rental     9603056         chutche
ETI      Scott Cable Comm.             99    ANNUAL POLE REN100000089              2/20/2001 15:26:33      Jan. 1, 2001 through Dec. 31, 2001            5951.58       5951.58      Annual      Rental     1059689         chutche
ETI      Scott Cable Comm.             99    ANNUAL POLE REN100000500              1/16/2002 09:41:12      Jan. 1, 2002 through Dec. 31, 2002            8934.43       8934.43      Annual      Rental     1075132         chutche
ETI      Scott Cable Comm.             99    ANNUAL POLE REN100000739              1/13/2003 09:05:14      Jan. 1, 2003 through Dec. 31, 2003            12390.3       12390.3      Annual      Rental     1092928         chutche
ETI      Scott Cable Comm.             99    ANNUAL POLE REN100001567              1/28/2004 11:25:13      Jan. 1, 2004 through Dec. 31, 2004            15355.5       15355.5      Annual      Rental     9601137         chutche
ETI      Scott Cable Comm.             99    ANNUAL POLE REN100002320              1/10/2005 09:20:26      Jan. 1, 2005 through Dec. 31, 2005           15500.23      15500.23      Annual      Rental     9601354         chutche
ETI      Scott Cable Comm.             99    ANNUAL POLE REN100003208              1/11/2006 07:51:35      Jan. 1, 2006 through Dec. 31, 2006           15510.82      15510.82      Annual      Rental     9601640         chutche
ETI      Scott Cable Comm.             99    ANNUAL POLE REN100004209              1/18/2007 08:06:34      Jan. 1, 2007 through Dec. 31, 2007           15510.82      15510.82      Annual      Rental     9601943         chutche
ETI      Scott Cable Comm.             99    ANNUAL POLE REN100005109              1/15/2008 15:11:43      Jan. 1, 2008 through Dec. 31, 2008           15510.82      15510.82      Annual      Rental     9602247         chutche
ETI      Scott Cable Comm.             99    ANNUAL POLE REN100006482              2/6/2009 14:09:23       Jan. 1, 2009 through Dec. 31, 2009           12545.62        12531.5     Annual      Rental     9602698         chutche
ETI      Scott Cable Comm.             99    ANNUAL POLE REN100007541              1/19/2010 10:18:29      Jan 1, 2010 through Dec. 31, 2010            12332.38                    Annual      Rental     9603037         chutche
ETI      Scott Cable Comm.             99    ANNUAL POLE REN1044685                11/2/2000 10:32:00      Jan. 1, 2000 through Dec. 31, 2000            5951.58        5951.58     Annual      Rental     1044685         chutche
ETI      Star Cable Associates        105    Annual pole rental fo100000088        2/20/2001 15:17:38      Jan. 1, 2001 through Dec. 31, 2001          20043.34       20043.34      Annual      Rental     1059693         rpascua
ETI      Star Cable Associates        105    Annual pole rental fo1044687          1/21/2000 00:00:00      Jan. 1, 2000 through Dec. 31, 2000              30005         30005      Annual      Rental     1044687         rpascua
ETI      TCI Cablevision              112    ANNUAL POLE REN100000085              2/15/2001 15:27:19      Jan. 1, 2001 through Dec. 31, 2001         136773.38      136773.38      Annual      Rental     1059475         chutche
ETI      TCI Cablevision              112    ANNUAL POLE REN100000501              1/16/2002 09:42:54      Jan. 1, 2002 through Dec. 31, 2002         136773.38      136773.38      Annual      Rental     1075135         chutche
ETI      TCI Cablevision              112    ANNUAL POLE REN100000741              1/14/2003 07:34:39      Jan. 1, 2003 through Dec. 31, 2003         137228.75      137228.75      Annual      Rental     1092935         chutche
ETI      TCI Cablevision              112    ANNUAL POLE REN100001568              1/28/2004 11:26:01      Jan. 1, 2004 through Dec. 31, 2004          131940.81      131940.81     Annual      Rental     9601138         chutche
ETI      TCI Cablevision              112    ANNUAL POLE REN100002321              1/10/2005 09:58:07      Jan. 1, 2005 through Dec. 31, 2005          133035.11      133035.11     Annual      Rental     9601355         chutche
ETI      TCI Cablevision              112    ANNUAL POLE REN100003209              1/11/2006 07:52:46      Jan. 1, 2006 through Dec. 31, 2006          133035.11      133035.11     Annual      Rental     9601641         chutche
ETI      TCI Cablevision              112    ANNUAL POLE REN100004210              1/18/2007 08:07:25      Jan. 1, 2007 through Dec. 31, 2007         133984.68      133984.68      Annual      Rental     9601944         chutche
ETI      TCI Cablevision              112    ANNUAL POLE REN100005110              1/15/2008 15:12:40      Jan. 1, 2008 through Dec. 31, 2008         134143.53      134143.53      Annual      Rental     9602248         chutche
ETI      TCI Cablevision              112    ANNUAL POLE REN100006483              2/6/2009 14:10:20       Jan. 1, 2009 through Dec. 31, 2009         134143.53      134143.53      Annual      Rental     9602699         chutche
ETI      TCI Cablevision              112    ANNUAL POLE REN100007542              1/19/2010 10:19:45      Jan 1, 2010 through Dec. 31, 2010          132224.35      132224.35      Annual      Rental     9603038         chutche
ETI      TCSI Huntsville, Inc         117    ANNUAL POLE REN100000079              2/15/2001 14:25:42      Jan. 1, 2001 through Dec. 31, 2001            4084.21        4084.21     Annual      Rental     1059476         chutche
ETI      TCSI Huntsville, Inc         117    ANNUAL POLE REN100000502              1/16/2002 09:47:43      Jan. 1, 2002 through Dec. 31, 2002            6152.79        6152.79     Annual      Rental     1075136         chutche
ETI      TCSI Huntsville, Inc         117    ANNUAL POLE REN100000730              1/13/2003 08:34:31      Jan. 1, 2003 through Dec. 31, 2003            6152.79        4095.81     Annual      Rental     1092938         chutche
ETI      TCSI Huntsville, Inc         117    ANNUAL POLE REN100001569              1/28/2004 11:27:18      Jan. 1, 2004 through Dec. 31, 2004            6145.73        5152.79     Annual      Rental     9601139         chutche
ETI      TCSI Huntsville, Inc         117    ANNUAL POLE REN100002322              1/10/2005 10:00:18      Jan. 1, 2005 through Dec. 31, 2005            6145.73        6145.73     Annual      Rental     9601356         chutche
ETI      TCSI Huntsville, Inc         117    ANNUAL POLE REN100003210              1/11/2006 07:54:10      Jan. 1, 2006 through Dec. 31, 2006            6145.73        6145.73     Annual      Rental     9601642         chutche
ETI      TCSI Huntsville, Inc         117    ANNUAL POLE REN100004211              1/18/2007 08:08:19      Jan. 1, 2007 through Dec. 31, 2007            6145.73        6145.73     Annual      Rental     9601945         chutche
ETI      TCSI Huntsville, Inc         117    ANNUAL POLE REN100005111              1/15/2008 15:13:46      Jan. 1, 2008 through Dec. 31, 2008            6145.73       4895.73      Annual      Rental     9602249         chutche
ETI      TCSI Huntsville, Inc         117    ANNUAL POLE REN100006484              2/6/2009 14:11:13       Jan. 1, 2009 through Dec. 31, 2009            6279.87         279.87     Annual      Rental     9602700         chutche
ETI      TCSI Huntsville, Inc         117    ANNUAL POLE REN100007543              1/19/2010 10:20:47      Jan 1, 2010 through Dec. 31, 2010              6173.13                   Annual      Rental     9603039         chutche
ETI      TCSI Huntsville, Inc         117    ANNUAL POLE REN1044689                1/21/2000 00:00:00      Jan. 1, 2000 through Dec. 31, 2000            4038.32       4038.32      Annual      Rental     1044689         chutche
ETI      Telecom Cable LLC           10123   ANNUAL POLE REN100006937              6/29/2009 17:09:38     April 1, 2009 through March 31, 2010               1000         1000      Annual      Rental     9602761         chutche
ETI      Telecom Cable LLC           10123   ANNUAL POLE REN100007718              1/27/2010 13:40:56      Jan 1, 2010 through Dec. 31, 2010               818.96                   Annual      Rental     9603054         chutche
ETI      Texas Telecable Inc         10054   ANNUAL POLE REN100000389              12/6/2001 16:56:34      Jan. 1, 2001 through Dec. 31, 2001              335.35       335.35      Annual      Rental     1072855         chutche
ETI      Texas Telecable Inc         10054   ANNUAL POLE REN100000729              1/13/2003 08:33:15      Jan. 1, 2003 through Dec. 31, 2003              335.35       335.35      Annual      Rental     1093107         chutche
ETI      Texas Telecable Inc         10054   ANNUAL POLE REN100001571              1/28/2004 11:30:04      Jan. 1, 2004 through Dec. 31, 2004              818.96       818.96      Annual      Rental     9601146         chutche
ETI      Texas Telecable Inc         10054   ANNUAL POLE REN100002323              1/10/2005 10:17:03      Jan. 1, 2005 through Dec. 31, 2005              818.96       818.96      Annual      Rental     9601363         chutche
ETI      Texas Telecable Inc         10054   ANNUAL POLE REN100003211              1/11/2006 07:56:31      Jan. 1, 2006 through Dec. 31, 2006              818.96       818.96      Annual      Rental     9601649         chutche
ETI      Texas Telecable Inc         10054   ANNUAL POLE REN100004212              1/18/2007 08:09:32      Jan. 1, 2007 through Dec. 31, 2007              818.96       818.96      Annual      Rental     9601952         chutche
ETI      Texas Telecable Inc         10054   ANNUAL POLE REN100005112              1/15/2008 15:14:48      Jan. 1, 2008 through Dec. 31, 2008              818.96                   Annual      Rental     9602256         chutche
ETI      Texas Telecable, Inc         120    ANNUAL POLE REN100000090              2/20/2001 15:28:02      Jan. 1, 2001 through Dec. 31, 2001          44305.03       44305.03      Annual      Rental     1059699         chutche
ETI      Texas Telecable, Inc         120    ANNUAL POLE REN100000503              1/16/2002 10:01:09      Jan. 1, 2002 through Dec. 31, 2002          44343.86       44343.86      Annual      Rental     1075137         chutche
ETI      Texas Telecable, Inc         120    ANNUAL POLE REN100000728              1/13/2003 08:31:25      Jan. 1, 2003 through Dec. 31, 2003          45339.32       45339.32      Annual      Rental     1093106         chutche
ETI      Texas Telecable, Inc         120    ANNUAL POLE REN100001572              1/28/2004 11:31:25      Jan. 1, 2004 through Dec. 31, 2004           46437.15      46437.15      Annual      Rental     9601140         chutche
ETI      Texas Telecable, Inc         120    ANNUAL POLE REN100002324              1/10/2005 10:25:15      Jan. 1, 2005 through Dec. 31, 2005          47552.63       47552.63      Annual      Rental     9601357         chutche
ETI      Texas Telecable, Inc         120    ANNUAL POLE REN100003212              1/11/2006 07:58:12      Jan. 1, 2006 through Dec. 31, 2006          47990.35       47990.35      Annual      Rental     9601643         chutche
ETI      Texas Telecable, Inc         120    ANNUAL POLE REN100004213              1/18/2007 08:10:41      Jan. 1, 2007 through Dec. 31, 2007           48173.91       48173.91     Annual      Rental     9601946         chutche
ETI      Texas Telecable, Inc         120    ANNUAL POLE REN100005113              1/15/2008 15:15:49      Jan. 1, 2008 through Dec. 31, 2008           48851.67      48851.67      Annual      Rental     9602250         chutche
ETI      Texas Telecable, Inc         120    ANNUAL POLE REN100006485              2/6/2009 14:12:03       Jan. 1, 2009 through Dec. 31, 2009          50768.46       50768.46      Annual      Rental     9602701         chutche
ETI      Texas Telecable, Inc         120    ANNUAL POLE REN100007544              1/19/2010 10:23:59      Jan 1, 2010 through Dec. 31, 2010            50082.51      50082.51      Annual      Rental     9603040         chutche
ETI      Timberlake Cablevision       121    ANNUAL POLE REN100000084              2/15/2001 15:21:02      Jan. 1, 2001 through Dec. 31, 2001           12294.99      12294.99      Annual      Rental     1059477         chutche
ETI      Timberlake Cablevision       121    ANNUAL POLE REN100000504              1/16/2002 10:03:20      Jan. 1, 2002 through Dec. 31, 2002               32123        32123      Annual      Rental     1075138         chutche
ETI      Timberlake Cablevision       121    ANNUAL POLE REN100000734              1/13/2003 08:45:38      Jan. 1, 2003 through Dec. 31, 2003           32137.12       32137.12     Annual      Rental     1092940         chutche
ETI      Timberlake Cablevision       121    ANNUAL POLE REN100001658              5/19/2004 14:54:47      Jan. 1, 2004 through Dec. 31, 2004           31653.51       31653.51     Annual      Rental     9601170         chutche
ETI      Timberlake Cablevision       121    ANNUAL POLE REN100002325              1/10/2005 10:26:32      Jan. 1, 2005 through Dec. 31, 2005           31653.51       31653.51     Annual      Rental     9601358         chutche
ETI      Timberlake Cablevision       121    ANNUAL POLE REN100003213              1/11/2006 08:00:28      Jan. 1, 2006 through Dec. 31, 2006           31653.51       31653.51     Annual      Rental     9601644         chutche
ETI      Timberlake Cablevision       121    ANNUAL POLE REN100004214              1/18/2007 08:11:39      Jan. 1, 2007 through Dec. 31, 2007           31653.51       31653.51     Annual      Rental     9601947         chutche
ETI      Timberlake Cablevision       121    ANNUAL POLE REN100005114              1/15/2008 15:16:54      Jan. 1, 2008 through Dec. 31, 2008           31653.51       31653.51     Annual      Rental     9602251         chutche
ETI      Timberlake Cablevision       121    ANNUAL POLE REN100006486              2/6/2009 14:12:53       Jan. 1, 2009 through Dec. 31, 2009           32959.61      32959.61      Annual      Rental     9602702         chutche
ETI      Timberlake Cablevision       121    ANNUAL POLE REN100007717              1/27/2010 13:32:43      Jan 1, 2010 through Dec. 31, 2010           32399.39                     Annual      Rental     9603041         chutche
ETI      Time Warner Cable            123    ANNUAL POLE REN100000076              2/15/2001 13:54:05      Jan. 1, 2001 through Dec. 31, 2001          44555.66       44555.66      Annual      Rental     1059478         chutche
ETI      Time Warner Cable            123    ANNUAL POLE REN100000545              4/15/2002 16:03:43      Jan. 1, 2002 through Dec. 31, 2002          44873.36       44873.36      Annual      Rental     1079126         chutche
ETI      Time Warner Cable            123    ANNUAL POLE REN100000742              1/14/2003 07:36:01      Jan. 1, 2003 through Dec. 31, 2003          44873.36       44873.36      Annual      Rental     1092942         chutche
ETI      Time Warner Cable            123    ANNUAL POLE REN100001574              1/28/2004 11:32:59      Jan. 1, 2004 through Dec. 31, 2004           42067.01      42067.01      Annual      Rental     9601142         chutche
ETI      Time Warner Cable            123    ANNUAL POLE REN100002329              1/10/2005 10:53:19      Jan. 1, 2005 through Dec. 31, 2005           42067.01      42067.01      Annual      Rental     9601359         chutche
ETI      Time Warner Cable            123    ANNUAL POLE REN100003214              1/11/2006 08:02:40      Jan. 1, 2006 through Dec. 31, 2006           42067.01      42067.01      Annual      Rental     9601645         chutche
ETI      Time Warner Cable            123    ANNUAL POLE REN100004215              1/18/2007 08:12:43      Jan. 1, 2007 through Dec. 31, 2007           42102.31       42102.31     Annual      Rental     9601948         chutche
ETI      Time Warner Cable            123    ANNUAL POLE REN100005115              1/15/2008 15:18:11      Jan. 1, 2008 through Dec. 31, 2008          42352.94       42352.94      Annual      Rental     9602252         chutche
ETI      Time Warner Cable            123    ANNUAL POLE REN100006487              2/6/2009 14:14:00       Jan. 1, 2009 through Dec. 31, 2009          42352.94       42352.94      Annual      Rental     9602703         chutche
ETI      Time Warner Cable            123    ANNUAL POLE REN100007545              1/19/2010 10:25:14      Jan 1, 2010 through Dec. 31, 2010            41775.33      41775.33      Annual      Rental     9603042         chutche
ETI      Time Warner Cable           10047   POLE RENTAL          100000416        12/10/2001 06:44:14     Jan. 1, 2001 through Dec. 31, 2001          29620.23       29620.23      Annual      Rental     1072854         chutche
ETI      Time Warner Cable           10047   POLE RENTAL          100000743        1/14/2003 07:37:50      Jan. 1, 2003 through Dec. 31, 2003          29620.23       29620.23      Annual      Rental     1092950         chutche
ETI      Time Warner Cable           10047   POLE RENTAL          100001575        1/28/2004 11:34:38      Jan. 1, 2004 through Dec. 31, 2004            32581.9        32581.9     Annual      Rental     9601145         chutche
ETI      Time Warner Cable           10047   POLE RENTAL          100002328        1/10/2005 10:51:35      Jan. 1, 2005 through Dec. 31, 2005            32581.9        32581.9     Annual      Rental     9601362         chutche
ETI      Time Warner Cable           10047   POLE RENTAL          100003215        1/11/2006 08:06:22      Jan. 1, 2006 through Dec. 31, 2006            32581.9        32581.9     Annual      Rental     9601648         chutche
ETI      Time Warner Cable           10047   POLE RENTAL          100004216        1/18/2007 08:14:32      Jan. 1, 2007 through Dec. 31, 2007            32581.9        32581.9     Annual      Rental     9601951         chutche
ETI      Time Warner Cable           10047   POLE RENTAL          100005116        1/15/2008 15:19:36      Jan. 1, 2008 through Dec. 31, 2008           32641.91       32641.91     Annual      Rental     9602255         chutche
ETI      Time Warner Cable           10047   POLE RENTAL          100006489        2/6/2009 14:16:19       Jan. 1, 2009 through Dec. 31, 2009          39592.48       39592.48      Annual      Rental     9602706         chutche
ETI      Time Warner Cable           10047   POLE RENTAL          100007547        1/19/2010 10:27:40      Jan 1, 2010 through Dec. 31, 2010            39047.91      39047.91      Annual      Rental     9603045         chutche
ETI      Time Warner Communicatio    10068   ANNUAL POLE REN100001576              1/28/2004 11:35:57      Jan. 1, 2004 through Dec. 31, 2004            9241.54        9241.54     Annual      Rental     9601148         chutche
ETI      Time Warner Communicatio    10068   ANNUAL POLE REN100002327              1/10/2005 10:46:58      Jan. 1, 2005 through Dec. 31, 2005            9241.54        9241.54     Annual      Rental     9601365         chutche
ETI      Time Warner Communicatio    10068   ANNUAL POLE REN100003216              1/11/2006 08:08:19      Jan. 1, 2006 through Dec. 31, 2006            9241.54        9241.54     Annual      Rental     9601651         chutche
ETI      Time Warner Communicatio    10068   ANNUAL POLE REN100004217              1/18/2007 08:16:27      Jan. 1, 2007 through Dec. 31, 2007            9241.54        9241.54     Annual      Rental     9601954         chutche
ETI      Time Warner Communicatio    10068   ANNUAL POLE REN100005117              1/15/2008 15:20:51      Jan. 1, 2008 through Dec. 31, 2008            9241.54        9241.54     Annual      Rental     9602258         chutche
ETI      T-N-T CABLE                 10114   ANNUAL POLE REN100006680              3/10/2009 09:16:32      Jan. 1, 2009 through Dec. 31, 2009            5019.66                    Annual      Rental     9602737         chutche
ETI      T-N-T CABLE                 10114   ANNUAL POLE REN100007640              1/21/2010 15:33:22      Jan 1, 2010 through Dec. 31, 2010             4934.34                    Annual      Rental     9603050         chutche
ETI      Ultra Services of America   10076   ANNUAL POLE REN100002597              3/21/2005 09:23:06      Jan. 1, 2005 through Dec. 31, 2005            1990.92       1990.92      Annual      Rental     9601500          jcastil
ETI      Ultra Services of America   10076   ANNUAL POLE REN100003217              1/11/2006 08:10:34      Jan. 1, 2006 through Dec. 31, 2006            1990.92       1990.92      Annual      Rental     9601653          jcastil
ETI      Versalink Media LLC         10129   ANNUAL POLE REN100007643              1/21/2010 15:36:13      Jan 1, 2010 through Dec. 31, 2010                10063                   Annual      Rental     9603055         chutche
         TOTAL YEARS 2001-2010                                                                                                                     $5,477,229.14 $4,926,706.43

                                                                                   Data Source:          S- Attachment Data System - March 24, 2010




                                                                                                                                                                                                                                      18
                       37744                                                                                                                                                                        OPUC 6-5 LR5306
                SOAH DOCKET NO. XXX-XX-XXXX
                  PUC DOCKET NO. 39896

                                 §
APPLICATION OF ENTERGY           §
TEXAS, INC. FOR AUTHORITY TO     §           PUBLIC UTILITY
CHANGE RATES, RECONCILE FUEL     §
COSTS, AND OBTAIN DEFERRED       §       COMMISSION OF TEXAS
ACCOUNTING TREATMENT             §




                  Direct Testimony and Exhibits

                               of

                      JEFFRY POLLOCK




                          On Behalf of

              Texas Industrial Energy Consumers




                          REDACTED




                          March, 2012
                                                                                                     Jeffry Pollock
                                                                                                     Direct Testimony
                                                                                                     Page 2



                                         SOAH DOCKET NO. XXX-XX-XXXX
                                            PUC DOCKET NO. 39896

                                                                   §
       APPLICATION OF ENTERGY                                      §
       TEXAS, INC. FOR AUTHORITY TO                                §                  PUBLIC UTILITY
       CHANGE RATES, RECONCILE FUEL                                §
       COSTS, AND OBTAIN DEFERRED                                  §           COMMISSION OF TEXAS
       ACCOUNTING TREATMENT                                        §


                                               TABLE OF CONTENTS

TABLE OF CONTENTS ....................................................................................................... 2
EXHIBIT LIST....................................................................................................................... 3
AFFIDAVIT OF JEFFRY POLLOCK ..................................................................................... 4
LIST OF ACRONYMS .......................................................................................................... 5
1. INTRODUCTION, QUALIFICATIONS AND SUMMARY ................................................... 6
      Summary ..................................................................................................................... 8
2. REVENUE REQUIREMENT ISSUES ..............................................................................15
     Test Year Versus Rate Year ...................................................................................... 15
     Purchased Power Capacity Costs ............................................................................. 21
     Transmission Equalization Payments ........................................................................ 27
     Depreciation Expense ............................................................................................... 33
     Property Tax Expense ............................................................................................... 39
     Incentive Compensation ............................................................................................ 41
     MISO Transition Costs .............................................................................................. 45
3. CLASS COST-OF-SERVICE STUDY ..............................................................................51
      Municipal Franchise Fees.......................................................................................... 52
      Miscellaneous Gross Receipts Taxes ........................................................................ 59
      Revised Class Cost-of-Service Study ........................................................................ 60
4. CLASS REVENUE ALLOCATION ...................................................................................63
5. RATE DESIGN ................................................................................................................68
      Schedule LIPS .......................................................................................................... 68
      Schedule SMS .......................................................................................................... 70
      Schedule AFC ........................................................................................................... 81
      Fixed Fuel Factor ...................................................................................................... 85
APPENDIX A.......................................................................................................................88
APPENDIX B.......................................................................................................................90
APPENDIX C ....................................................................................................................101


                                                        J.POLLOCK
                                                      INCORPORATED
                                                                    Jeffry Pollock
                                                                    Direct Testimony
                                                                    Page 3



                                      EXHIBIT LIST


Exhibit JP-1: Derivation of Test Year Adjusted Purchased Power Capacity Costs
Exhibit JP-2: Pro-Forma Adjustment to Recognize the Expiration of the EAI-WBL
              Agreement
Exhibit JP-3: Schedule MSS-2 Equalization Calculation for May 2011
Exhibit JP-4: ETI’s Response to Cities 3-3(g)
Exhibit JP-5: Comparison of Book Reserve and Theoretical Reserve By Function
Exhibit JP-6: Comparison of Book Reserve and Theoretical Reserve For the General Plant
              Accounts
Exhibit JP-7: Incentive Compensation Expense (Contains Highly Sensitive Information)
Exhibit JP-8: Year-To-Year Variation in Expenses By FERC Accounts in Which MISO
              Transition Costs are Being Booked
Exhibit JP-9: Municipal Franchise Fee Rate By City; Inside City kWh Sales; Municipal
              Franchise Fees By Customer Class
Exhibit JP-10: Allocation Factors for Miscellaneous Gross Receipts Taxes
Exhibit JP-11: Revised Texas Retail Class Cost-of-Service Study At Present Rates
Exhibit JP-12: ETI's Proposed Class Revenue Allocation
Exhibit JP-13: Recommended Class Revenue Allocation Based on TIEC's Revised Class
               Cost-of-Service Study
Exhibit JP-14: Schedule LIPS Rate Design
Exhibit JP-15: Derivation of Schedule SMS Charges
Exhibit JP-16: Schedule SMS Coincidence Ratio
Exhibit JP-17: Derivation of Option A Rider AFC Charge at ETI's Proposed Revenue
               Requirements
Exhibit JP-18: Derivation of Option B Rider AFC Charge at ETI's Proposed Revenue
               Requirements
Exhibit JP-19: Fixed Fuel Factor Loss Multipliers




                                       J.POLLOCK
                                      INCORPORATED
                                                                                         Jeffry Pollock
                                                                                         Direct Testimony
                                                                                         Page4



                                            SOAH DOCKET NO. XXX-XX-XXXX
                                               PUC DOCKET NO. 39896

                                                              §
                 APPLICATION OF ENTERGY                       §
                 TEXAS, INC. FOR AUTHORITY TO                 §             PUBLIC UTILITY
                 CHANGE RA TES, RECONCILE FUEL                §
                 COSTS, AND OBTAIN DEFERRED                   §        COMMISSION OF TEXAS
                 ACCOUNTING TREATMENT                         §


                                         AFFIDAVIT OF JEFFRY POLLOCK


        State of Missouri            )
                                     ) SS
        County of St. Louis )


                    Jeffry Pollock, being first duly sworn, on his oath states:

                    1. My name is Jeffry Pollock. I am President of J. Pollock, Incorporated, 12655
        Olive Blvd., Suite 335, St. Louis, Missouri 63141. We have been retained by Texas Industrial
        Energy Consumers to testify in this proceeding on its behalf;

                 2.     Attached hereto and made a part hereof for all purposes is my Direct
        Testimony, Exhibits and Appendices A, B and C which have been prepared in written form
        for introduction into evidence in Public Utility Commission of Texas Docket No. 39896; and,

               3. I hereby swear and affirm that my answers contained in the testimony are true
        and correct.



                                                                                  Jeffry Pollock

                                                          thi~ day of M~
                   Subscribed and sworn to before me
r-~---::~~TJY~ru=RNER==-~~-
     Notary Publlc - Notary Seal
         S~emMJs~oo
                                                   P
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                                                      /~-~
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                                                         ~~~~r--~~~~~~~~~~'°T-~~~
                                                                                   0
  CommlssionedforUncolnCounty               ~-Kitty Tu      er Netary Public
My Commission ~res: Aprjl 25, 2015                   ·       -:..L-·
  Commission Numbar: 1139                          C    mts ion #: 11390610

                   My Commission expires on April 25, 2015.




                                                       J.POLLOCK
                                                    INCORPORATED
                                                  Jeffry Pollock
                                                  Direct Testimony
                                                  Page 5



               LIST OF ACRONYMS
   Term                        Definition
AFC          Additional Facilities Charge
Commission   Public Utility Commission of Texas
EAIP         Executive Annual Incentive Plan
EGSI         Entergy Gulf States, Inc.
EOP          Equity Ownership Plan
EPS          Earnings Per Share
ESA          Entergy System Agreement
ETI          Entergy Texas, Inc.
IS           Interruptible Service
kW           Kilowatt
kWh          Kilowatt Hour
kW-Month     Kilowatt-Month
LIPS         Large Industrial Power Service
LTIP         Long Term Incentive Plan
MFF          Municipal Franchise Fees
MGRT         Miscellaneous Gross Receipts Taxes
MISO         Midwest Independent System Operator
MW           Megawatt
O&M          Operation & Maintenance
PPA          Purchased Power Agreement
PPR          Purchased Power Rider
PURA         Public Utility Regulatory Act
PURPA        Public Utility Regulatory Policies Act
QF           Qualifying Facilities
ROR          Rate of Return
RROR         Relative Rate of Return
SMS          Standby and Maintenance Service
TIEC         Texas Industrial Energy Consumers
UCOS         Unbundled Cost-of-Service




                    J.POLLOCK
                   INCORPORATED
                                                                        Jeffry Pollock
                                                                        Direct Testimony
                                                                        Page 6




                            Direct Testimony of Jeffry Pollock


1               1. INTRODUCTION, QUALIFICATIONS AND SUMMARY


2    Q   PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.

3    A   Jeffry Pollock; 12655 Olive Blvd., Suite 335, St. Louis, MO 63141.


4    Q   WHAT IS YOUR OCCUPATION AND BY WHOM ARE YOU EMPLOYED?

5    A   I am an energy advisor and President of J.Pollock, Incorporated (J.Pollock).


6    Q   PLEASE STATE YOUR EDUCATIONAL BACKGROUND AND EXPERIENCE.

7    A   I have a Bachelor of Science Degree in Electrical Engineering and a Masters in

8        Business Administration from Washington University. Since graduation in 1975, I

9        have been engaged in a variety of consulting assignments, including energy

10       procurement and regulatory matters in both the United States and several Canadian

11       provinces. I have participated in nearly every contested regulatory proceeding at the

12       Public Utility Commission of Texas (Commission) involving Entergy Texas, Inc. (ETI)

13       and its predecessor Entergy Gulf States, Inc. (EGSI).         My qualifications are

14       documented in Appendix A.        A partial list of my appearances is provided in

15       Appendix B to this testimony.


16   Q   ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING?

17   A   I am testifying on behalf of Texas Industrial Energy Consumers (TIEC).           TIEC

18       members are customers of ETI, and they purchase electricity primarily under the



                                                                 1. Introduction, Qualifications
                                                                                  And Summary

                                         J.POLLOCK
                                         INCORPORATED
                                                                           Jeffry Pollock
                                                                           Direct Testimony
                                                                           Page 7



1        Large Industrial Power Service (LIPS), Interruptible Service (IS), Standby and

2        Maintenance Service (SMS), and Experimental As-Available Power Service (EAPS)

3        rate schedules.


4    Q   WHAT ISSUES ARE YOU ADDRESSING?

5    A   I am addressing various revenue requirement, cost allocation and rate design issues

6        raised by ETI in this proceeding; specifically:

7              Revenue Requirement Issues (Part 2):
8                   o   Purchased Power Capacity Costs;
9                   o   Transmission Equalization Payments;
10                  o   Depreciation;
11                  o   Property Taxes;
12                  o   Incentive Compensation; and
13                  o   MISO Transition Costs.
14             Cost Allocation Issues:
15                  o   Retail Class Cost-of-Service Study (Part 3); and
16                  o   Class Revenue Allocation (Part 4).
17             Rate Design Issues (Part 5):
18                  o   Schedule LIPS;
19                  o   Schedule SMS;
20                  o   Schedule AFC; and
21                  o   Fixed Fuel Factor Loss Multipliers.

22       The fact that I am not addressing other issues should not be interpreted as an

23       endorsement of ETI’s proposals on these issues.




                                                                 1. Introduction, Qualifications
                                                                                  And Summary

                                          J.POLLOCK
                                          INCORPORATED
                                                                        Jeffry Pollock
                                                                        Direct Testimony
                                                                        Page 8



1    Summary

2    Q   PLEASE SUMMARIZE YOUR FINDINGS AND CONCLUSIONS.

3    A   My findings and conclusions are as follows:

4        Revenue Requirements
5           Purchased Power Capacity Costs

6               ETI’s proposed pro-forma adjustments to purchased power capacity costs

7        were derived from cost projections for a future period, which ETI refers to as the

8        “Rate Year.” ETI substituted Rate Year estimates for Test Year costs. A Rate Year

9        is not a Test Year. Substituting Rate Year costs for Test Year costs violates the

10       Commission rules, which require that rates be set using an historical Test Year

11       adjusted for known and measurable changes. In other words, a Test Year is used to

12       set rates. Further, post-test year adjustments are allowed only when the utility also

13       reflects all attendant effects. If a pro-forma adjustment assumes post-test year load

14       growth, it should also reflect the additional revenues associated with load growth.

15       Post-test year adjustments must also be consistent with the Matching Principle; that

16       is, if rates are set using Test Year sales, the costs must also be based on the Test

17       Year. ETI’s proposal would set rates using Rate Year costs and Test Year sales,

18       which would ignore increases in ETI’s revenue caused by load growth from the Test

19       Year to the Rate Year. Thus, ETI’s proposal would violate the Matching Principle

20       and the Commission’s rules that require that rate and cost parameters be based on

21       the same time period.




                                                                 1. Introduction, Qualifications
                                                                                  And Summary

                                         J.POLLOCK
                                        INCORPORATED
                                                                              Jeffry Pollock
                                                                              Direct Testimony
                                                                              Page 9



1                      For all of these reasons, the Commission should reject any post-test year

2              adjustments that use Rate Year projections for Test Year costs as ETI has done. If

3              the Commission were to make such post-test year adjustments, however, the proper

4              adjusted amount of purchased power capacity costs is $236.89 million or $6.661 per

5              kW-Month, which is a reduction of $39.350 million from ETI’s request.1 The $39.350

6              million reduction is based on re-pricing Test Year capacity purchases under the

7              known PPAs.

8                 Transmission Equalization Payments

9                      ETI’s proposed post-test year adjustment to transmission equalization

10             payments should be rejected because ETI has failed to demonstrate that the

11             requested pro-forma adjustment is known and measurable.                 Transmission

12             equalization payments are a function of three variables: inter-transmission

13             investment, ownership costs and responsibility ratios. Estimating these variables is

14             susceptible to a host of uncertainties, such as the timing of new transmission

15             investment, the cost of money, operating expenses, taxes and load growth, which

16             determines the responsibility ratios. Further complicating the analysis is that such

17             estimates require specific assumptions not only for ETI, but for all Entergy Operating

18             Companies.      Should the Commission decide that a pro-forma adjustment is

19             appropriate, a reasonable approach would be to annualize the average monthly

20             transmission equalization payments incurred by ETI from January through June 2011




     1
         All amounts are stated on a Total Company basis.

                                                                       1. Introduction, Qualifications
                                                                                        And Summary

                                                 J.POLLOCK
                                                 INCORPORATED
                                                                     Jeffry Pollock
                                                                     Direct Testimony
                                                                     Page 10



1    (the last six months of the Test Year). This will reduce ETI’s proposed transmission

2    equalization expense by $8 million.

3       Depreciation Expense

4           My recommendation on depreciation expense reflects two separate

5    adjustments. First, no increase in the depreciation rates applicable to production

6    plant accounts is warranted because ETI has accumulated a substantial surplus

7    depreciation reserve. This would reduce ETI’s proposed depreciation expense by

8    $1.156 million. Second, it is unnecessary to amortize a $21.3 million deficiency in

9    the general plant depreciation reserve as ETI proposed because the deficiency can

10   be largely cured by reallocating the reserve from those general plant accounts that

11   presently have a significant surplus. This reallocation of the depreciation reserve

12   within the general plant accounts is consistent with accepted practice. The net effect

13   of this adjustment is a reduction of $794,000. Thus, the combined adjustment for

14   these two recommendations is to reduce ETI’s requested depreciation expense by

15   $1.95 million. I have not addressed issues related to salvage value and useful life.

16      Property Taxes

17          ETI has failed to prove that any adjustment in property tax expense is

18   warranted. ETI’s proposed adjustment assumes that property tax rates are affected

19   primarily by projected net operating income, rather than net plant in service. Further,

20   ETI has assumed a 1% increase in tax rates that is not tied to any specific known

21   changes. ETI’s proposed $2.6 million increase to its Test Year property tax expense

22   should be rejected.


                                                              1. Introduction, Qualifications
                                                                               And Summary

                                     J.POLLOCK
                                     INCORPORATED
                                                                      Jeffry Pollock
                                                                      Direct Testimony
                                                                      Page 11



1       Incentive Compensation

2           I am recommending that all incentive compensation related to achieving

3    financial goals ($6.2 million) be removed from ETI’s revenue requirements.          My

4    recommendation is consistent with past Commission precedent.

5       MISO Transition Costs

6           ETI’s request for deferred accounting of transition expenses related to

7    Entergy’s proposal to join the Midwest Independent System Operator (MISO) should

8    be rejected because there is no proof that deferred accounting is required for ETI to

9    carry out various provisions of PURA. ETI is not required by law to join MISO, nor

10   are the MISO costs of a substantial nature that would jeopardize ETI’s financial

11   integrity. Further, costs incurred of a similar nature (including ETI’s request to join

12   ERCOT) have not been subject to deferred accounting.

13          ETI’s alternative proposal (i.e., to remove all transition costs incurred during

14   the Test Year, restate expenses to collect $4 million per year in MISO costs, and

15   amortize costs incurred prior to 2011 over five years with a return) should also be

16   rejected. The $4 million is not based on Test Year expenses (which were less than

17   $1 million). Including future costs in rates is not only an impermissible post-test year

18   adjustment, it would violate the Matching Principle. Even if Entergy (ETI’s parent)

19   could exactly estimate its total transition costs, ETI’s share of these expenditures is

20   based on an estimated responsibility ratio of 17%.           However, the estimated

21   responsibility ratio assumes post-test year load growth. Absent a specific adjustment

22   to recognize additional revenues from post-test year load growth, ETI’s pro-forma


                                                              1. Introduction, Qualifications
                                                                               And Summary

                                      J.POLLOCK
                                      INCORPORATED
                                                                      Jeffry Pollock
                                                                      Direct Testimony
                                                                      Page 12



1    adjustment would not take all attendant effects into account and should be rejected.

2    Highlighting the uncertainty of these costs, ETI’s estimate increased from $12 million

3    to $17 million (a 40% increase) in the span of only three months. Thus, these costs

4    are not known and measurable. Finally, the costs are immaterial relative to other

5    similar expenses. The proper treatment of MISO transition expenses reduces ETI’s

6    request by $3.8 million.


7    Class Cost-of-Service Study

8           ETI’s class cost-of-service study should be revised so that the allocation of

9    municipal franchise fees (MFF) and miscellaneous state gross receipts taxes

10   (MGRT) reflect cost causation. ETI allocates these taxes on revenues. This is not

11   consistent with cost causation. MFF are caused by kWh sales inside cities. Further,

12   different cities charge different MFF rates, and class sales are not uniformly

13   distributed by city. As a result, the weighted average MFF rate differs by class. This

14   difference should be recognized. MGRT are caused by revenues inside city limits.


15   Class Revenue Allocation

16          All rates should be moved to cost in this case.         This is consistent with

17   Commission policy, and it will promote rates that are equitable, efficient, provide

18   stability (of net revenues) and encourage conservation.


19   Rate Design

20      Schedule LIPS

21          Schedule LIPS should be revised to include a customer charge. Further,

                                                               1. Introduction, Qualifications
                                                                                And Summary

                                     J.POLLOCK
                                     INCORPORATED
                                                                      Jeffry Pollock
                                                                      Direct Testimony
                                                                      Page 13



1    because the non-fuel energy charges are already higher than non-fuel energy costs,

2    if there is any additional increase allocated to the LIPS class, it should be applied to

3    the demand charges. Any decrease (after taking into account additional customer

4    charge revenues) should be applied to the energy charges.

5       Schedule SMS

6           Schedule SMS should be redesigned to better reflect the cost characteristics

7    of Standby and Maintenance power customers. Specifically, the demand charge for

8    production/transmission-related costs should recognize that Standby service seldom

9    occurs coincident with ETI’s monthly summer peaks; that is, Standby power has a

10   much lower coincidence factor than full-requirements power. Based on an analysis

11   of Standby customers’ historical usage characteristics, the Standby power

12   production/transmission demand charge should be set at 12% (reflecting the ratio of

13   Standby to LIPS coincidence factors) of the corresponding Schedule LIPS demand

14   charges. There should also be a separate demand charge for distribution service,

15   consistent with the current non-fuel energy charges. The energy charge should be

16   the same as under Schedule LIPS except during on-peak hours.              The on-peak

17   energy charge should provide for recovery of additional demand-related costs not

18   already recovered in the SMS demand charge. This will provide a strong incentive to

19   minimize forced outages during on-peak hours while ensuring that an SMS customer

20   pays no more than a full-requirements customer for similar service. This approach is

21   consistent with system-wide costing principles because it recognizes the same cost

22   causative factors used to allocate production and transmission demand-related


                                                              1. Introduction, Qualifications
                                                                               And Summary

                                      J.POLLOCK
                                      INCORPORATED
                                                                    Jeffry Pollock
                                                                    Direct Testimony
                                                                    Page 14



1    costs, and SMS customers would pay the same distribution and non-fuel energy

2    charges as LIPS customers.

3       Schedule AFC

4             Schedule AFC rates should be reduced consistent with ETI’s Test Year

5    ownership and operating costs associated with facilities that are directly assigned to

6    specific customers. Specifically, the Option A rate should be 1.20% per month, while

7    the Option B Monthly Recovery rates should also be reduced. Further, the Option B

8    O&M (Operation and Maintenance) Rate should be reduced to 0.35%, consistent

9    with the percent of O&M expenses related to transmission and distribution plant

10   investment. The recommended rates should be correspondingly lower if adjustments

11   are made to ETI’s overall rate of return, distribution O&M expenses, or property

12   taxes.

13      Fixed Fuel Factor Loss Multipliers

14            ETI has revised its demand and energy losses in this proceeding.         The

15   revised losses are reflected in the jurisdictional and class cost-of-service studies.

16   The same energy losses should also be used to reset the loss multipliers in the Fixed

17   Fuel Factor.




                                                             1. Introduction, Qualifications
                                                                              And Summary

                                     J.POLLOCK
                                     INCORPORATED
                                                                           Jeffry Pollock
                                                                           Direct Testimony
                                                                           Page 15




                           2. REVENUE REQUIREMENT ISSUES


1    Q    WHAT REVENUE REQUIREMENT ISSUES ARE YOU ADDRESSING?

2    A     I am addressing each of the following expenses:

3               Purchased Power Capacity Costs;
4               Transmission Equalization Payments;
5               Depreciation;
6               Property Taxes;
7               Incentive Compensation; and
8               MISO Transition Costs.

9         In this case, ETI is using the Test Year ended June 30, 2011. My analysis reveals

10        that, with respect to purchased power capacity costs and transmission equalization

11        payments, ETI has calculated an “adjusted test year” expense using projected

12        expenditures for a future period, which ETI refers to as the “Rate Year.”      ETI’s

13        proposed Rate Year is the period from June 2012 through May 2013. As explained

14        later, substituting Rate Year expenditures for Test Year adjusted expenses is

15        seriously flawed, contrary to accepted ratemaking practice and this Commission’s

16        rules, and would result in rates that are neither just nor reasonable.

17   Test Year Versus Rate Year

18   Q    WHAT IS A TEST YEAR?

19   A    The Commission’s rules define a Test Year as:

20               The most recent 12 months for which operating data for an electric
21               utility, electric cooperative, or municipally-owned utility are
22               available and shall commence with a calendar quarter or a fiscal



                                                                 2. Revenue Requirement Issues

                                           J.POLLOCK
                                           INCORPORATED
                                                                                    Jeffry Pollock
                                                                                    Direct Testimony
                                                                                    Page 16



1                         year quarter. 2

2    Q         WHAT IS A RATE YEAR?

3    A          The Commission’s rules define a Rate Year as:

4                         The 12-month period beginning with the first date that rates
5                         become effective. The first date that rates become effective may
6                         include, but is not limited to, the effective date for bonded rates or
7                         the effective dates for interim or temporary rates.3

8    Q         WHICH PERIOD IS USED TO SET RATES, A TEST YEAR OR A RATE YEAR?

9    A         The Commission’s rules require the use of a Test Year to set rates. Specifically:

10                        (b) Allowable expenses.      Only those expenses which are
11                        reasonable and necessary to provide service to the public shall be
12                        included in allowable expenses. In computing an electric utility’s
13                        allowable expenses, only the electric utility’s historical test
14                        year expenses as adjusted for known and measurable
15                        changes will be considered, except as provided for in any
16                        section of these rules dealing with fuel expenses.4 (emphasis
17                        added).

18   Q         DOES THE USE OF AN HISTORICAL TEST YEAR PRECLUDE A UTILITY FROM

19             MAKING PRO-FORMA ADJUSTMENTS TO RECOGNIZE CHANGES IN COSTS

20             THAT HAVE OCCURRED SUBSEQUENT TO THE TEST YEAR?

21   A         No. A utility can make pro-forma adjustments to actual Test Year expenses that are

22             both known and measurable.            A pro-forma adjustment is “known” if it can be

23             anticipated with reasonable certainty. For example, if a utility enters into a new

24             purchased power agreement (PPA) after the close of the Test Year, this is a known

25             change, and it may be reasonable to reflect the new PPA in calculating adjusted Test



     2
         P.U.C. SUBST. R. 25.5(134).
     3
         Id. 25.5(102).
     4
         Id. 25.231(b).

                                                                          2. Revenue Requirement Issues

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1        Year expenses, assuming that all attendant impacts can be taken into account. A

2        pro-forma adjustment is “measurable” if the impact of a known change can be

3        quantified with reasonable certainty by restating expenses as if the change had

4        occurred at the beginning of the Test Year.


5    Q   ARE THERE ANY OTHER REQUIREMENTS THAT GOVERN HOW KNOWN AND

6        MEASURABLE CHANGES TO TEST YEAR RESULTS ARE QUANTIFIED?

7    A   Yes. First, a pro-forma adjustment should reflect all attendant effects. For example,

8        if a utility installs a more efficient billing system and wants to recover the full cost of

9        the system in rates it must also reflect any increase in productivity resulting from the

10       new billing system. This might include reducing wages and benefits to recognize a

11       lower employee count, or reducing working capital if the new billing system reduces

12       the time required to render bills. Recognizing all attendant effects is also consistent

13       with Commission’s rules. Specifically, the Commission’s rule for invested capital

14       provides:

15              (F) Requirements for post test year adjustments.

16              (i)    Post test year adjustments for known and measurable rate
17              base additions (increases) to historical test year data will be
18              considered only as set out in subclauses (I)-(IV) of this clause.

19                                                * * *
20              (IV) Where the attendant impacts on all aspects of a utility’s
21              operations (including but not limited to, revenue, expenses and
22              invested capital) can with reasonable certainty be identified,
23              quantified and matched.      Attendant impacts are those that




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1                       reasonably follow as a consequence of the post test year adjustment
2                       being proposed.5 (emphasis added)

3    Q         WHAT OTHER PRINCIPLE SHOULD BE RECOGNIZED IN MAKING PRO-FORMA

4              ADJUSTMENTS TO TEST YEAR EXPENSES?

5    A         A pro-forma adjustment must also recognize the “Matching Principle.” The Matching

6              Principle means using a consistent set of assumptions for all ratemaking

7              components (e.g., sales, revenues, invested capital and operating expenses). The

8              fundamental premise behind the Matching Principle is the fact that rates are set as

9              follows:




10             Thus, in order to set rates, the costs must be determined for the same test year as

11             the corresponding sales.      If costs are based on a future period when sales are

12             projected to be 10% higher, but sales are based on an historical test year, the utility’s

13             rates would over-collect costs by 10%.


14   Q         IS THE MATCHING PRINCIPLE RECOGNIZED IN THIS COMMISSION’S RULES?

15   A         Yes. The Commission’s rules state that:

16                      (b) Rates will be determined using revenues, billing and usage data
17                      for a historical test year adjusted for known and measurable changes,
18                      and costs of service as defined in §25.231 of this title (relating to Cost
19                      of Service).6




     5
         P.U.C. SUBST. R. 25.231(c)(2)(F).
     6
         P.U.C. SUBST. R. 25.234(b).

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1    Q   PLEASE PROVIDE AN EXAMPLE TO ILLUSTRATE HOW THESE TWO

2        FUNDAMENTAL PRINCIPLES ARE PROPERLY RECOGNIZED.

3    A   Let’s assume that Utility A and Utility B both file rate cases in Dec. 2011 using a June

4        2011 Test Year and a May 2013 Rate Year. Also assume that when these cases

5        were filed, it was known that a new PPA would become effective May 2013.

6        Consider the following scenarios:

 7              Utility A measures the impact of the new PPA by restating test year
 8              expenses as if the PPA had been in effect for the entire test year.
 9              This includes eliminating any expenses that would be affected by the
10              new PPA, such as removing an expiring PPA and/or retiring
11              generating capacity, provided that the total quantity of capacity
12              resources in the test year is unchanged. All other test year
13              assumptions are unchanged.

14              Utility B measures the impact of the new PPA by simply estimating
15              the additional expense over a future period in which the new PPA is in
16              effect and then adding this estimated expense to test year expenses.
17              No other adjustments are made.

18       In this example, Utility A has reflected attendant effects (given that it is not seeking

19       recovery of additional capacity costs to serve post-test year load growth), while using

20       consistent Test Year assumptions to set rates. If the purpose of the new PPA is to

21       allow Utility B to serve projected additional loads, Utility B failed to measure all

22       attendant effects in the new PPA.       Further, Utility B has violated the Matching

23       Principle because adjusted Test Year purchased power capacity costs would, in part,

24       reflect post Test Year load growth while the rate would reflect Test Year sales. The

25       resulting rate would allow Utility B to over-recover costs.




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1    Q   WITH REGARD TO THE ABOVE EXAMPLE, WOULD ETI’S QUANTIFICATION

2        OF    PURCHASED        POWER       CAPACITY       COSTS     AND     TRANSMISSION

3        EQUALIZATION PAYMENTS MORE CLOSELY RESEMBLE UTILITY A OR

4        UTILITY B?

5    A   Utility B. For this reason, it is necessary to adjust ETI’s claimed expenses so that

6        they reflect appropriate ratemaking practices and are consistent with this

7        Commission’s rules.


8    Q   WOULD PROPER APPLICATION OF THESE TWO FUNDAMENTAL CONCEPTS

9        ENSURE THAT RATES ARE JUST AND REASONABLE?

10   A   Yes. When these two fundamental concepts (i.e., reflect all attendant affects and

11       recognize the Matching Principle) are correctly applied, pro-forma adjustments to

12       Test Year expenses can provide a better representation of the costs that the utility

13       will incur when new base rates are implemented.


14   Q   PLEASE SUMMARIZE YOUR DISCUSSION OF THE USE OF A TEST YEAR

15       VERSUS A RATE YEAR IN SETTING RATES.

16   A   Proper ratemaking practice means establishing a utility’s costs of providing a service

17       for an historical Test Year adjusted for known and measurable changes. Any pro-

18       forma adjustments to Test Year costs must be reasonably anticipated, reflect all

19       attendant effects and use the same assumptions as are used in determining the

20       utility’s other costs and in developing rates (i.e. consistent with the Matching

21       Principle). This requires that Test Year expenses be restated as if a known and

22       measurable change had occurred at the beginning of the Test Year. It would not be

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1             appropriate to substitute an expense derived from a future time period (i.e. the Rate

2             Year) for Test Year expenses without making all appropriate adjustments.

3    Purchased Power Capacity Costs

4    Q        WHAT ARE PURCHASED POWER CAPACITY COSTS?

5    A        Purchased power capacity costs are expenses incurred under a PPA for the right to

6             call on a specific amount of capacity.        They are typically comprised of demand

7             charges and other option payments, which are generally fixed for a specified term

8             and are not affected by the amount of kilowatt-hours (kWh) purchased.


9    Q        WHY ARE PURCHASED POWER CAPACITY COSTS AN ISSUE IN THIS CASE?

10   A        First, purchased power capacity costs are considered non-reconcilable; that is, a

11            utility can only recover purchased power capacity costs in base rates. Second, in its

12            Supplemental Preliminary Order, the Commission decided that it would not address

13            ETI’s proposed Purchased Power Rider.7 Under the proposed Purchased Power

14            Rider, ETI would have collected all purchased power capacity costs outside of base

15            rates. The Supplemental Preliminary Order also stated that the Commission needs

16            to determine the amount of purchased power capacity costs to be recovered in base

17            rates. Because rates are defined on a per-unit basis, it would also be appropriate to

18            state the allowable purchased power capacity costs on a per kilowatt-month (kW-

19            Month) basis.




     7
         Supplemental Preliminary Order at 2 (Jan. 19, 2012).

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1    Q      HAVE YOU ANALYZED ETI’S PROPOSAL TO RECOVER PURCHASED POWER

2           CAPACITY COSTS IN BASE RATES?

3    A      Yes. ETI is proposing to recover $276 million of “adjusted test year” purchased

4           power capacity costs in base rates.8


5    Q      HOW WAS THE $276 MILLION DERIVED?

6    A      ETI projected its capacity purchases under PPAs that would be in place during the

7           Rate Year (June 2012-May 2013). It then substituted these Rate Year expenses for

8           the Test Year expenses in determining ETI’s overall cost of service in this

9           proceeding.


10   Q      ARE ETI’S RATE YEAR PURCHASES BASED ON THE SAME ASSUMPTIONS

11          AS ITS TEST YEAR POWER PURCHASES?

12   A      No. For example, the projected quantity of capacity purchases is clearly different in

13          the Rate Year than during the Test Year as shown in the table below.

                                    Table 1: Rate Year vs. Test Year
                                               Quantities
                                             (MW-Months)
                                      Purchase           Test      Rate
                                                         Year      Year
                              Third Party Purchases       5,584    12,834
                              Affiliate Purchases        21,670    21,711
                              MSS-1 Payments              8,309     5,262
                                 Total                   35,563    39,807




     8
        Direct Testimony of Robert R. Cooper at 20. Another ETI witness, Mr. Considine, stated that the
     amount of purchased power capacity costs ETI is seeking to recover are the costs that were removed
     from the Test Year. However, $246.6 million of costs were removed from the Test Year (Considine at
     26 and Adjustment No. 24). This testimony is contradicted by Mr. Cooper’s testimony.

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1        As can be seen, ETI’s Rate Year purchases (39,807 MW-Months) would be nearly

2        12% higher than the corresponding Test Year purchases (35,563 MW-Months).


3    Q   WHY ARE RATE YEAR PURCHASES HIGHER THAN TEST YEAR PURCHASES?

4    A   Rate year purchases reflect the fact that ETI is projecting to serve additional load

5        during the Rate Year. As discussed later, most of the $30 million spread between

6        Rate Year ($276 million) and Test Year ($245 million) purchased power capacity

7        costs is due to additional capacity purchases.       These additional purchases are

8        primarily related to meeting future loads, while maintaining an appropriate reserve

9        margin.


10   Q   DID ETI MAKE ANY OTHER ADJUSTMENTS TO RATE YEAR PURCHASED

11       POWER CAPACITY COSTS?

12   A   No.   ETI did not recognize additional revenues from post-test year load growth.

13       Thus, ETI’s post-test year adjustment fails to recognize all attendant effects. Further,

14       rates would be set using Rate Year costs and Test Year sales. Thus, this approach

15       would clearly violate the Matching Principle as previously discussed.


16   Q   SHOULD ETI’S RATE YEAR PURCHASED POWER CAPACITY COSTS BE USED

17       TO SET RATES IN THIS PROCEEDING?

18   A   No. ETI’s use of Rate Year expenses is not consistent with accepted ratemaking

19       practices or this Commission’s rules. For all of these reasons, ETI’s proposed post-

20       test year adjustments should be rejected. Rates should be set using actual Test

21       Year expenses.


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1    Q       IF THE COMMISSION DETERMINES THAT AN ADJUSTMENT TO TEST YEAR

2            EXPENSES IS APPROPRIATE, HOW SHOULD ADJUSTED TEST YEAR

3            PURCHASED POWER CAPACITY COSTS BE QUANTIFIED?

4    A       Actual Test Year costs should be used as the starting point. Pro-forma adjustments

5            should reflect the capacity costs associated with “known” PPAs. Further, consistent

6            with the Matching Principle, only changes in per-unit capacity costs, and not changes

7            in the quantity of power purchased, should be measured. This will ensure that the

8            costs used to set rates are based on the same time period as the billing

9            determinants.


10   Q       WHAT DO YOU MEAN BY “KNOWN” PURCHASED POWER AGREEMENTS?

11   A       Known PPAs are executed agreements that have been submitted for Commission

12           review and have been found to be prudent. This could include PPAs where power

13           may not have flowed during the Test Year but will commence during the Rate Year.

14           However, it also means that a pro-forma adjustment should also be made to remove

15           a PPA if it is reasonably anticipated that it will expire (i.e., power will stop flowing)

16           during the Rate Year.


17   Q       HAVE YOU QUANTIFIED ETI’S ADJUSTED TEST YEAR PURCHASED POWER

18           CAPACITY COSTS?

19   A       Yes. This is shown in Exhibit JP-1. The starting point was ETI’s actual Test Year

20           expenses. As can be seen, these expenses were $245 million (line 2).9 I then


     9
      The $245 million excludes $1.6 million of costs associated with the Toledo Bend purchase. This is
     comparable with ETI’s proposed $276 million.

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1        quantified Test Year per-unit costs (column 3) by dividing the Test Year costs

2        (column 1) by the corresponding amount of Test Year capacity purchases (column

3        2).       Pro-forma adjustments were made solely to recognize changes in per-unit

4        capacity costs associated with known PPAs. The pro-forma unit costs are based on

5        analysis of all known PPAs (column 4).


6    Q   HOW DID YOU QUANTIFY THE PRO-FORMA ADJUSTMENTS?

7    A   First, I categorized ETI’s PPAs into three separate groups:

8                  Third-Party Purchases (line 3);
9                  Affiliate Purchases (line 4); and
10                 Reserve Equalization Payments (line 5).

11       I then applied the unit costs of the known PPAs (column 4) to Test Year capacity

12       purchases (column 2).          This resulted in adjusted Test Year purchased power

13       capacity costs of about $248 million (line 6). This is slightly higher than ETI’s actual

14       Test Year costs and about $28 million below ETI’s proposed adjusted Test Year

15       expense ($276 million- $248 million).


16   Q   SHOULD         ANY FURTHER          ADJUSTMENTS BE MADE TO               TEST YEAR

17       PURCHASED POWER CAPACITY COSTS?

18   A   Yes. It is currently known that the EAI-WBL PPA will expire at the end of 2012. To

19       ensure that rates reflect ETI’s going-forward costs, Test Year expenses should be

20       adjusted to recognize this known change.




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1    Q   WHAT IS THE EAI-WBL AGREEMENT?

2    A   The EAI-WBL (which is an acronym for Entergy Arkansas, Inc.-Wholesale Base

3        Load) agreement is a firm capacity purchase of about 107 megawatts (MW) of power

4        from a “pool” of wholesale generating resources. The resources include both nuclear

5        and coal plants owned by Entergy Arkansas, Inc. (EAI). This capacity purchase was

6        for a three-year term beginning in January 2010. Thus, the EAI-WBL PPA will expire

7        in December 2012, which is only five months after the jurisdictional deadline for this

8        case.


9    Q   HAVE YOU QUANTIFIED AN ADJUSTMENT TO REMOVE THE EAI-WBL PPA?

10   A   Yes. This adjustment is shown in Exhibit JP-2. As can be seen, I have removed

11       $13.86 million of expense, which represents the costs of EAI-WBL PPA for seven

12       months of the Test Year. It is reasonable to assume that ETI would make additional

13       Reserve Equalization purchases for about the same quantity, or 746 MW-Months as

14       shown on line 3. These pro-forma unit costs of reserve equalization purchases is

15       $3.659 per kW-Month (line 4). Applying the pro-forma unit costs and the additional

16       purchases would result in an offsetting adjustment of $2.73 million (line 5). Thus, the

17       net effect of removing the EAI-WBL PPA would be an $11.1 million (line 6)

18       adjustment to Test Year purchased power capacity costs.


19   Q   SHOULD ANY ADJUSTMENT BE MADE TO REFLECT A POTENTIAL NEW EAI-

20       WBL PURCHASED POWER AGREEMENT?

21   A   No. Any adjustment would be inappropriate. ETI has not yet submitted a new EAI-

22       WBL PPA for Commission review, and Commission review is essential to determine

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1             whether this agreement is prudent.                Until such time as the Commission has

2             determined a new EAI-WBL PPA is prudent, no post-test year adjustment associated

3             with such a potential contract should be made in setting base rates.10


4    Q        PLEASE SUMMARIZE YOUR RECOMMENDATION ON ETI’S ADJUSTED TEST

5             YEAR OF PURCHASED POWER CAPACITY COSTS.

6    A        Test Year adjusted purchased power capacity costs should be set at $236.89 million,

7             or $6.661 per kW-Month ($236.89 million ÷ 35,563 MW-Months ÷ 1,000) on a Total

8             Company basis. This is based on Test Year capacity purchases, and it reflects

9             changes in the per-unit costs under all known PPAs. It also reflects the expiration of

10            the EAI-WBL PPA, which is currently scheduled to occur during the Rate Year. The

11            $236.89 million represents a $39.350 million reduction in ETI’s proposed adjusted

12            Test Year expense.

13   Transmission Equalization Payments

14   Q        WHAT ARE TRANSMISSION EQUALIZATION PAYMENTS?

15   A        The Entergy System Agreement (ESA) requires that all Entergy Operating

16            Companies equalize certain transmission costs.                    The equalization process is


     10
         However, if an adjustment is to be made, it should not exceed $5.944 million, which is derived as
     follows:
              Line                Description                Amount                Source
               1     Demand Charge Differential Between                 Derived from ETI’s Responses
                     the Original and New EAI-WBL                       To TIEC 5-1 (Addendum 1).
                     Agreements (per kW-Month)
               2     EAI-WBL Purchases Removed                 746      Exhibit JP-2, line 2.
                     (MW-Months)
               3     Adjustment (Millions)                    $5.944    Line 1 x Line 2.

     This would result in adjusted Test Year purchased power capacity costs of $242.080 million, which is a reduction
     of $34.162 million from ETI’s request.

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1              accomplished through Schedule MSS-2. Schedule MSS-2 equalizes the ownership

2              and operating costs associated with inter-transmission investment between Entergy

3              Affiliates. Inter-transmission investment includes:

4                     All of the investment in transmission lines operated at 230 kV or
5                      higher voltage;
 6                    Investment in transmission substations with three or more lines
 7                     operated at a voltage of 230 kV or higher, including facilities down to,
 8                     but not including, the high side disconnecting device at the
 9                     transformer, 50% of common facilities, and other facilities as
10                     approved by the Operating Committee; and
11                    All lines 115 kV and higher from the owning company’s last substation
12                     to the connecting point of another Company (either Entergy System
13                     Company, or nonsystem Company) not included in the above.11

14   Q         WHAT LEVEL OF TRANSMISSION EQUALIZATION PAYMENTS IS ETI

15             PROPOSING TO REFLECT IN SETTING RATES IN THIS PROCEEDING?

16   A         ETI is proposing to collect $10.697 million of transmission equalization payments in

17             setting rates for this proceeding.12


18   Q         WHAT WAS THE BASIS FOR THE $10.697 MILLION OF TEST YEAR

19             TRANSMISSION EQUALIZATION PAYMENTS?

20   A         The $10.697 million was ETI’s estimated Rate Year transmission equalization

21             expense.13




     11
          Direct Testimony of Patrick J. Cicio at Exhibit PJC-1 at 38.
     12
          Schedule P, Adjustment 23.
     13
          Direct Testimony of Michael P. Considine at 25.

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1    Q         WHAT      TRANSMISSION         EQUALIZATION         PAYMENTS       WERE    ACTUALLY

2              INCURRED DURING THE TEST YEAR?

3    A         ETI incurred $1.754 million of transmission equalization payments in the Test Year.14

4              Thus, ETI is proposing a pro-forma adjustment of about $8.9 million to Test Year

5              actual expense.


6    Q         SHOULD ETI’S PROPOSED PRO-FORMA ADJUSTMENT TO TRANSMISSION

7              EQUALIZATION PAYMENT BE ADOPTED?

8    A         No. As previously stated, the $10.697 million Test Year adjusted amount is based

9              on the Rate Year June 2012 through May 2013. That is, all components of the

10             Schedule MSS-2 equalization process reflect Rate Year estimates, including future

11             net inter-transmission investment, future ownership costs, and future responsibility

12             ratios.   Further, ETI has failed to demonstrate that the requested pro-forma

13             adjustment is known and measurable. Transmission equalization payments are a

14             function of three variables: inter-transmission investment, ownership/operating costs

15             and responsibility ratios, which determine ETI’s share of system investment.

16             Estimating these variables is susceptible to a host of uncertainties, such as the

17             timing of new transmission investment, the cost of money, operating expenses, taxes

18             and load growth. Further complicating the analysis is that such estimates require

19             specific assumptions not only for ETI, but for all Entergy Operating Companies.




     14
          ETI Response to Cities 3-3(g), which is enclosed as Exhibit JP-4.

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1    Q   PLEASE EXPLAIN.

2    A   Exhibit JP-3 provides an illustration showing how Schedule MSS-2 equalizes inter-

3        transmission investment. The illustration is for the month of May 2011. The starting

4        point is net inter-transmission investment for each Entergy Operating Company (lines

5        1-4). The next step is to quantify the ownership and operating costs associated with

6        inter-transmission investment, which are the product of net investment (line 4) and

7        the sum of the following cost components stated as a percentage of investment:

8                Ownership costs, such as the cost of money (lines 5-11), state and
9                 federal income taxes (line 12) and depreciation expense (line 13); and
10               Operating costs, including insurance, property tax, franchise tax,
11                operation & maintenance and overheads (lines 14-18).

12       Total annual ownership/operating costs (line 20) are the sum of the individual cost

13       components. They are translated into dollar amounts (line 21), which is the product

14       of each operating company’s net inter-transmission investment (line 4) and the

15       annual     ownership/operating    cost   percentage    (line   20).    Total      system

16       ownership/operating costs (column 2, line 22) and net inter-transmission investment

17       (column 3, line 22) are the sum of the corresponding amounts for each operating

18       company. Dividing the two amounts yields the system average ownership/operating

19       costs shown in column 5, line 22 (annual) and line 23 (monthly).

20                Inter-transmission cost responsibility is then calculated for each operating

21       company. It is the product of the total system net transmission investment (column

22       4, line 22) and each operating company’s responsibility ratio (line 24).            The

23       difference between each operating company’s inter-transmission cost responsibility

24       (line 25) and its actual net transmission investment (line 4) represents the investment

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1        difference. A corresponding payment (receipt) under Schedule MSS-2 is the product

2        of the investment difference (line 26) and the system monthly ownership costs

3        (column 5, line 23).

4               As can be seen, for the month of May 2011, ETI would have paid the other

5        Entergy Operating Companies $131,500 in transmission equalization payments.


6    Q   WHAT IS A RESPONSIBILITY RATIO?

7    A   The responsibility ratio measures each Entergy Operating Company’s contribution to

8        System load requirements. As can be seen in Exhibit JP-3, ETI’s responsibility ratio

9        for Schedule MSS-2 was 16.09% in May 2011.


10   Q   WHAT RESPONSIBILITY RATIO IS ETI ASSUMING IN ITS RATE YEAR

11       CALCULATIONS?

12   A   ETI is assuming a responsibility ratio of about 17% for the Rate Year.         This

13       represents a significant increase over the Test Year responsibility ratios, which

14       averaged about 15.4%.


15   Q   WHAT WOULD CAUSE ETI’S RESPONSIBILITY RATIO TO INCREASE?

16   A   An operating company’s load responsibility reflects the actual monthly peak

17       demands served by each operating company. Thus, increasing responsibility ratios

18       mean that an operating company is expecting above-average load growth relative to

19       the other operating companies.




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1    Q   SHOULD ETI’S PROPOSED PRO-FORMA ADJUSTMENT TO TEST YEAR

2        TRANSMISSION EQUALIZATION PAYMENTS BE ACCEPTED?

3    A   No. ETI’s proposed pro-forma adjustment should be rejected because it requires

4        speculation about a host of variables, including future transmission investment,

5        ownership costs and load growth, not just for ETI, but for all Entergy Operating

6        Companies. Thus, the adjustment is not known and measurable.

7               Further, ETI’s proposal is an impermissible post-test year adjustment. That

8        is, ETI is substituting a projected expense from a future period for the actual Test

9        Year expense without reflecting all attendant adjustments, such as the additional

10       revenues from post-test year load growth. This is the same problem as discussed

11       previously with ETI’s proposed purchased power capacity costs. Similarly, ETI is

12       proposing to recover this inflated cost over adjusted Test Year sales. Thus, ETI’s

13       proposal also violates the Matching Principle.


14   Q   SHOULD THE COMMISSION DETERMINE THAT A PRO-FORMA ADJUSTMENT

15       FOR TRANSMISSION EQUALIZATION PAYMENTS IS APPROPRIATE, HOW

16       SHOULD THE ADJUSTMENT BE QUANTIFIED?

17   A   The determination should reflect the level of transmission equalization payments that

18       ETI has incurred in the Test Year, adjusted for any known and measurable changes.

19       As can be seen in Exhibit JP-4, ETI’s Test Year payments were $1.754 million,

20       which is roughly $146,200 per month. However, during the last six months of the

21       Test Year (January-June 2011), ETI incurred $1.35 million of transmission

22       equalization payments, which is roughly $225,000, or 1.5 times, the monthly average


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1               Test Year expense.15 Recognizing the higher costs in the last six months of the Test

2               Year, a pro-forma adjustment equal to twice the amount of transmission equalization

3               payments incurred during the first six months of 2011 would be reasonable. This

4               results in an adjusted Test Year expense of $2.7 million. This would reduce ETI’s

5               adjusted Test Year amount by about $8 million.

6    Depreciation Expense

7    Q          HAVE YOU REVIEWED THE TESTIMONY CONCERNING DEPRECIATION AS

8               FILED BY ETI IN THIS PROCEEDING?

9    A          Yes. ETI is proposing to increase Test Year depreciation expense by $16.2 million.16

10              The $16.2 million reflects changes in the depreciation rates applicable to most plant

11              accounts as well as a $2.1 million per year “catch-up” adjustment to amortize a $21.3

12              million depreciation reserve deficiency in certain of its general plant accounts over

13              ten years.17 I have not reviewed the reasonableness of ETI’s proposed life spans

14              and net salvage values.


15   Q          DO YOU AGREE WITH ETI’S PROPOSED INCREASE IN TEST YEAR

16              DEPRECIATION EXPENSE?

17   A          No. First, it would be inappropriate to increase depreciation rates for those functional

18              accounts that currently have a significant surplus depreciation reserve. This is the

19              case for ETI’s production plant accounts, for which ETI is proposing a $1.156 million

     15
          Id.
     16
          Direct Testimony of Dane Watson at 6-7.
     17
        In Errata No. 4, ETI filed a corrected depreciation study. Based on this study, it is proposing a
     $13.9 million increase (Watson Revised Errata No. 4 at 7). However, Errata No. 4 does not impact
     the two depreciation issues that are being addressed in this testimony.

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1        increase. Second, the proposed catch-up adjustment is unnecessary because it

2        ignores the significant surplus that ETI has accumulated in certain general plant

3        accounts, which can be used to offset most of the deficiency.         Reallocating the

4        reserve from the surplus to the deficit accounts is an accepted practice.


5    Q   WHAT DO YOU MEAN BY A SURPLUS DEPRECIATION RESERVE?

6    A   A surplus depreciation reserve occurs when actual book depreciation exceeds the

7        “required” or “theoretical” reserve as determined in a recent depreciation study. The

8        required reserves reflect the life span and net salvage assumptions that are critical to

9        determining depreciation rates.


10   Q   HOW IS THE REQUIRED OR THEORETICAL DEPRECIATION RESERVE

11       CALCULATED?

12   A   The required or theoretical reserve is derived in a depreciation study based on the

13       estimated life spans, interim retirements and removal costs associated with each

14       FERC Account and/or subaccount.


15   Q   HAS ETI PRESENTED A DEPRECIATION STUDY THAT QUANTIFIES THE

16       ACTUAL BOOK DEPRECIATION AND THEORETICAL RESERVES?

17   A   Yes. ETI’s depreciation study is provided in Schedule D-5. It is sponsored by Mr.

18       Dane A. Watson.


19   Q   WHY ARE THE LIFE SPAN AND COST-OF-REMOVAL ASSUMPTIONS CRITICAL

20       IN DETERMINING DEPRECIATION RATES?

21   A   Depreciation accounting provides for the recovery of the original cost of an asset

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1        over its life span adjusted for net salvage. Under the PUC’s Substantive Rules,

2        depreciation rates are calculated using the straight-line method.            The most

3        commonly used straight-line method is the remaining life method. Remaining life

4        depreciation rates are derived using the following formula:




5        Under the remaining life method, the un-depreciated portion of the plant in service,

6        adjusted for net salvage, is recovered over the average remaining life of the asset or

7        group of assets.     Therefore, at the end of the useful life, the asset is fully

8        depreciated.

9               As a result, it is critical that an appropriate average life span be used to

10       develop the depreciation rates so that present and future ratepayers are treated

11       equitably. In addition to capital recovery, depreciation rates also contain a provision

12       for net salvage. Net salvage is the value of the scrap or reused materials less the

13       removal cost of the asset being depreciated. A utility will reflect in its rates the net

14       salvage over the useful life of the asset.


15   Q   HOW DOES ETI’S CALCULATED BOOK DEPRECIATION RESERVE COMPARE

16       WITH THE THEORETICAL RESERVE?

17   A   The comparison is shown in Exhibit JP-5. It is based on the corrected depreciation

18       study provided by Mr. Watson following his deposition.          As can be seen, ETI

19       currently has a $92.5 million surplus in its production accounts (line 1) and a $3.7

20       million surplus in its transmission accounts (line 2).     The distribution plant and

21       general plant accounts have reserve deficiencies of $98.8 million (line 3) and $4.1

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1             million (line 6), respectively, based on the life spans and net salvage values

2             assumed by ETI.


3    Q        DOES ETI ACKNOWLEDGE THAT THERE CAN BE DIFFERENCES BETWEEN

4             THE BOOK AND THEORETICAL DEPRECIATION RESERVES?

5    A        Yes. This fact is acknowledged by Mr. Watson, who states:

 6                    With respect to ETI, my depreciation study demonstrates that there
 7                    have been significant changes in the life of the property over the last
 8                    15 years. These changes have created differences between the
 9                    theoretical and the book reserve in each functional group that make
10                    the reallocation of the depreciation reserve appropriate in this
11                    instance.18

12   Q        WOULD THE MAGNITUDE OF A DEPRECIATION RESERVE SURPLUS OR

13            DEFICIENCY BE AFFECTED IF THE ASSUMED LIFE SPANS AND NET

14            SALVAGE VALUES WERE ALTERED?

15   A        Yes. Changes in either assumption would affect the magnitude of a depreciation

16            reserve surplus or deficiency. Long life spans and/or higher net salvage values

17            would result in a lower required or theoretical reserve, thereby increasing the surplus

18            or reducing a deficit.


19   Q        WHAT IS THE SIGNIFICANCE OF A DEPRECIATION RESERVE SURPLUS?

20   A        Depreciation should occur ratably over the life of an asset. This ensures that both

21            present and future customers are treated equitably; that is, they pay only for the

22            portion of the facilities that is used to provide electric service. A depreciation surplus

23            means that the current generation of customers has paid a disproportionate share of

     18
          Direct Testimony of Dane Watson at 10-11.

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1        the plant investment. Without an adjustment, future customers will not pay their

2        appropriate share of the investment. Thus, a surplus depreciation reserve means

3        that current customers are subsidizing future customers. In other words, there is

4        inter-generational inequity.


5    Q   WOULD THERE ALSO BE INTER-GENERATIONAL INEQUITY IF THE UTILITY

6        HAS A SIGNIFICANT DEPRECIATION RESERVE DEFICIENCY?

7    A   Yes.


8    Q   HOW CAN INTER-GENERATIONAL EQUITY BE RESTORED?

9    A   With respect to production plant, inter-generational equity can be partially restored by

10       rejecting ETI’s proposed increase in depreciation rates applicable to production plant

11       accounts.


12   Q   WHY IS THERE A SIGNIFICANT DEFICIENCY IN CERTAIN GENERAL PLANT

13       RESERVE ACCOUNTS?

14   A   ETI retired equipment (consisting mostly of computers) prior to end of the assumed

15       life span of these assets.     This resulted in a $21.3 million deficiency.      ETI is

16       proposing to amortize this deficiency over ten years so that the book reserve will

17       eventually “catch-up” with the theoretical depreciation reserve for the deficient

18       accounts.


19   Q   IS IT NECESSARY FOR ETI TO AMORTIZE THE $21 MILLION DEFICIENCY?

20   A   No. A catch up adjustment is unnecessary because the $21 million deficiency would

21       be nearly offset by the depreciation surplus in other general plant accounts. This is

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1               shown in Exhibit JP-6. As can be seen, the overall general plant reserve has a

2               small ($4.1 million) deficiency.


3    Q          CAN      THE    DEPRECIATION         RESERVE      BE    REALLOCATED         BETWEEN

4               ACCOUNTS SO THAT ANY SURPLUS ACCOUNTS CAN BE USED TO OFFSET

5               THE DEFICIENT ACCOUNTS?

6    A          Yes. It is common practice to reallocate the depreciation reserve from the surplus

7               accounts to the deficient accounts within the same functional group, such as general

8               plant.


9    Q          DOES ETI’S DEPRECIATION WITNESS CONCUR THAT THIS IS AN ACCEPTED

10              PRACTICE?

11   A          Yes. In his testimony, Mr. Dane Watson, stated that:

12                       The practice of depreciation reserve reallocation is endorsed in the
13                       1968 publication of “Public Utility Depreciation Practices,” National
14                       Association of Regulatory Utility Commissioners (“NARUC”), which
15                       explains that reallocation of the depreciation reserve is appropriate
16                       “…where the change in the view concerning the life of property is so
17                       drastic as to indicate a serious difference between the theoretical and
18                       the book reserve.” Additionally, the 1996 edition of the NARUC
19                       publication states that “theoretical reserve studies also have been
20                       conducted for the purpose of allocating an existing reserve among
21                       operating units or accounts.”19

22   Q          WOULD ALLOCATING A DEPRECIATION RESERVE FROM THE SURPLUS TO

23              THE DEFICIENT GENERAL PLANT ACCOUNTS REQUIRE ANY FURTHER

24              ADJUSTMENT?

25   A          Yes. Allocating the surplus reserve from the depreciable general plant accounts to


     19
          Id.

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1         the deficient accounts will require a $1.3 million increase in the annual accruals to

2         achieve full recovery over the remaining lives of the surplus accounts. Thus, the net

3         impact of my recommended adjustments to ETI’s Test Year depreciation expense

4         would be $0.794, as shown in the following table.

                            Table 2: Summary of Recommended
                      Adjustments to Test Year Depreciation Expenses
                                                           Amount
                                                       ($ in Millions)
                         Function
                                              Accruals Adjusted
                                              As Filed Accruals Difference
              General - Depreciable Accounts    $1,605      $2,946     $ 1,341
              General - Amortization Accounts   $5,947      $5,947     $     0
              Deficient Reserve Amortization       $2,135      $    0      ($2,135)
              General Plant Total                  $9,687      $8,893      ($ 794)


5    Q    PLEASE SUMMARIZE YOUR RECOMMENDED DEPRECIATION EXPENSE.

6    A    The Commission should reject ETI’s proposal to increase production depreciation

7         rates at this time given that the production depreciation reserve has a considerable

8         surplus. The Commission should also reject ETI’s proposed general plant “catch-up”

9         adjustment because the deficiency can largely be cured by reallocating the reserve

10        from the surplus to the deficit general plant accounts. This recommendation reduces

11        ETI’s proposed depreciation expense by $1.950 million ($1,156,000 + $794,000) on

12        a Total Company basis.

13   Property Tax Expense

14   Q    IS ETI PROPOSING TO ADJUST PROPERTY TAX EXPENSES?

15   A    Yes. ETI is proposing a $2.6 million pro-forma adjustment to Test Year expense.



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1    Q   WHAT IS THE BASIS FOR ETI’S PROPOSED $2.6 MILLION PRO-FORMA

2        ADJUSTMENT?

3    A   The $2.6 million pro-forma adjustment is based on an assumption that property taxes

4        will increase by 10.81% over Test Year levels. The 10.81% increase is comprised of

5        two components:

6              Weighted average growth in taxable property (9.81%); and
7              The annual tax rate “creep” (1%).

8        The growth in taxable property was based on the increase in net plant and net

9        operating income from 2010-2011. ETI projected a 3.7% increase in net plant and

10       an 11.33% increase in net operating income. Applying the 20%/80% weighting to

11       these growth rates resulted in a weighted average growth rate of 9.81%. ETI then

12       added the annual tax rate creep of 1% to arrive at the 10.81% growth rate.


13   Q   SHOULD ETI’S PROPOSED PRO-FORMA ADJUSTMENT BE ADOPTED?

14   A   No. Property taxes are assessed on valuation. For utility property, valuation is best

15       reflected by the net investment, not by net operating income. Further, ETI has failed

16       to explain why it weighted net plant only 20% while weighting net operating income

17       by 80% in calculating the assumed growth rate of its taxable property. Finally, the

18       1% annual tax rate creep is not based on specific changes in property tax rates or

19       assessments. Thus, it is not a known and measurable change.


20   Q   WHAT DO YOU RECOMMEND?

21   A   ETI has failed to adequately document the assumptions behind a 10.81% increase in

22       Test Year property tax expense. Therefore, ETI’s proposed pro-forma adjustment


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1         should be rejected.

2    Incentive Compensation

3    Q    WHAT IS MEANT BY INCENTIVE COMPENSATION?

4    A    Incentive compensation is the additional compensation paid to employees to

5         encourage certain behavior and/or results. It is paid as a reward for the individual

6         and business group achieving pre-established goals and objectives. Payment is

7         contingent on the employee/business unit achieving the goals.


8    Q    WHY IS INCENTIVE COMPENSATION AN ISSUE IN SETTING RATES?

9    A    Not all incentive compensation is beneficial to ratepayers.        As I discuss below,

10        incentive compensation based on achieving certain operational goals may be a

11        reasonable and necessary expense which may benefit ratepayers.                However,

12        incentive compensation that is targeted to achieve certain financial goals is only for

13        the benefit of shareholders and provides little, if any, benefit to ratepayers. Thus, the

14        latter expenses should not be charged to ratepayers.


15   Q    IS ETI PROPOSING TO RECOVER COSTS INCURRED UNDER VARIOUS

16        INCENTIVE COMPENSATION PROGRAMS IN BASE RATES?

17   A    Yes. ETI has included $18.7 million of incentive compensation in the Test Year. Of

18        this amount, $14.2 million was expensed and $4.5 million was capitalized.


19   Q    SHOULD ETI BE ALLOWED FULL RECOVERY OF ALL PROJECTED

20        INCENTIVE COMPENSATION PAYMENTS?

21   A    No. Incentive compensation that is based on achieving certain financial goals of


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1              Entergy, the parent of ETI, should be disallowed on the basis that it benefits only

2              shareholders not customers. As discussed later, at least $6.2 million of expense was

3              incurred to achieve financial objectives and should be disallowed. This includes

4              incentive compensation associated with affiliate (i.e., Entergy Services, Inc.)

5              expenses.


6    Q         WHAT      INCENTIVE       COMPENSATION        PLANS     DOES      ETI   OFFER      ITS

7              EMPLOYEES?

8    A         ETI and ESI have two primary types of incentive compensation plans:

9                  1. Annual; and
10                 2. Long-Term.

11             These plans and proposed Test Year expenses are listed on Exhibit JP-7.


12   Q         WHAT ARE THE ANNUAL INCENTIVE COMPENSATION PLANS?

13   A         There are various annual incentive compensation plans including the Management

14             Incentive Plan, Exempt Incentive Plan, Teamsharing Incentive Plan, Teamsharing

15             Selected Bargaining Units Incentive Plan and Operational Incentive Plan.             In

16             addition, there is also an Executive Annual Incentive Plan (“EAIP”) for Entergy

17             Company officers. Q WHAT PERFORMANCE GOALS trigger additional payouts

18             under THE ANNUAL PLANS?

19   A         In general, the payouts under the Annual plans are based on cost control,

20             operational and safety measures. In addition, [       of the ESI portion of the EAIP is

21             related to financial measures such as earnings per share (EPS) and stock price.20

     20
          Exhibit KGG-4 (Highly Sensitive).

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1          As can be seen in Exhibit JP-7, the Annual plans accounted for about $8.8 million of

2          Test Year incentive expenses.


3    Q     WHAT ARE THE LONG TERM INCENTIVE COMPENSATION PLANS?

4    A     The Long-Term incentive plans include the Equity Ownership Plan (EOP) and

5          various long term incentive plans (LTIP). The LTIP include four programs, the Long

6          Term Incentive Program, the Equity Awards Program, Restricted Shares Award

7          Program, and the Restricted Stock Award Programs. These LTIP plans are limited

8          to only senior executives with the exception that Directors are eligible for the

9          Restricted Stock Awards Program.


10   Q     WHAT PERFORMANCE GOALS TRIGGER ADDITIONAL COMPENSATION

11         UNDER THE LONG TERM PLANS?

12   A     The payouts under all of the Long-Term plans are entirely related to financial

13         measures such as stock price and shareholder earnings of the parent company,

14         Entergy. They are not tied to the results of the operating company, ETI. As can be

15         seen in Exhibit JP-7, the Long-Term plans accounted for about $5.4 million of Test

16         Year incentive compensation expense.


17   Q     WHAT PORTION OF THE TEST YEAR INCENTIVE COMPENSATION EXPENSE

18         IS RELATED TO ACHIEVING FINANCIAL OBJECTIVES?

19   A     As previously stated, [       of the EAIP and all of the Long-Term compensation

20         plans are related to achieving financial objectives. Together these account for $6.2

21         million of the $14.2 million of incentive compensation expensed during the Test Year.

22         The derivation of the $6.2 million is shown in column 5.
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1    Q      WHAT DO YOU RECOMMEND?

2    A      I recommend that $6.2 million of incentive compensation expense be disallowed.


3    Q      WHAT IS THE BASIS FOR YOUR RECOMMENDATION?

4    A      My recommendation is consistent with past precedent.             In past cases the

5           Commission has disallowed the portion of incentive compensation tied to corporate

6           financial objectives.   Specifically, in the Final Order of Docket No. 28840 which

7           involved AEP Central, the Commission allowed incentive compensation to the extent

8           that it was tied to operational factors. To the extent the compensation was the result

9           of financial measures, the payment was viewed as beneficial to shareholders and not

10          ratepayers and was disallowed.          In allowing some recovery of incentive

11          compensation, the Commission found that:

12                 169.    The financial measures are of more immediate benefit to
13                         shareholders, and the operating measures are of more
14                         immediate benefit to ratepayers.

15                 170.    Incentives to achieve operational measures are necessary and
16                         reasonable to provide T&D utility services, but those to
17                         achieve financial measures are not.21

18          The Commission also confirmed this opinion in the Order on Rehearing of Docket

19          No. 35717. This order states:

20                 92.     Incentive compensation based on financial measures or goals
21                         is of more immediate benefit to shareholders.

22                 93.     Of the amount Oncor requested for incentive compensation,
23                         $5,082,326 should be removed because it is related to


     21
        Application of AEP Texas Central Company for Authority to Change Rates, Docket No. 28840,
     Final Order at FOF 169-170 (Aug. 15, 2005).

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1                           financial measures that are unreasonable and unnecessary for
2                           the provision of T&D utility services.22

3    Q      PLEASE SUMMARIZE YOUR RECOMMENDATION.

4    A      All of the incentive compensation related to financial measures included in the Test

5           Year should be excluded from the calculation of the rates in this proceeding,

6           resulting in a total reduction of $6.2 million to incentive compensation.

7    MISO Transition Costs

8    Q      HOW IS ETI PROPOSING TO TREAT THE COSTS INCURRED TO SUPPORT

9           THE TRANSITION THE MIDWEST INDEPENDENT SYSTEM OPERATOR (MISO)?

10   A      ETI’s primary proposal is to defer all MISO transition costs incurred after 2010.

11          Specifically, it would create a regulatory asset, accumulate the transition costs as

12          incurred, accrue carrying charges (at ETI’s weighted average cost of capital) on the

13          balance of the accrued transition costs, and seek recovery for all prudent and

14          reasonable transition costs in a subsequent rate case. The pre-2011 Test Year

15          expenses would be amortized and recovered over a five-year period.23


16   Q      HAS ETI INCURRED TRANSITION COSTS DURING THE TEST YEAR?

17   A      Yes. ETI has incurred nearly $1 million of transition costs during the Test Year as

18          follows:



     22
        Application of Oncor Electric Delivery Company, LLC for Authority to Change Rates, Docket No.
     35717, Order on Rehearing at FOF 92-93 (Nov. 30, 2009).
     23
        Application Of Entergy Texas, Inc. For Authority To Defer Expenses Related To Its Proposed
     Transition To Membership In The Midwest Independent Transmission System Operator, Docket No.
     39741 at Application, and Docket No. 39896 at Schedule P Workpapers, Volume 2, Adjustment
     16.20.

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                                      Table 3: MISO Transition Costs
                                      Expensed During the Test Year

                                                Period           Amount
                                                                  ($000)
                                      July-December, 2010        $263.91
                                      January – June, 2011       $652.63
                                      Project F3PPSPE01824       $ 81.09
                                        Total                    $997.63

1               These costs would be removed from ETI’s Test Year cost of service if the deferred

2               accounting proposal is approved.


3    Q          HAS ETI PROPOSED AN ALTERNATIVE TREATMENT IF ITS DEFERRED

4               ACCOUNTING PROPOSAL IS REJECTED?

5    A          Yes. In the alternative, ETI proposes to include $4 million of expense to reflect ETI’s

6               share of the projected MISO transition costs. The alternative proposal also includes

7               recovery of pre-2011 expenses over five years.        This would result in an annual

8               expense of $52,800. The net effect would be a pro-forma adjustment to Test Year

9               operating expenses to $3.8 million ($4 million - $263,900 + $52,800).25


10   Q          SHOULD ETI’S DEFERRED ACCOUNTING PROPOSAL BE APPROVED?

11   A          No. ETI asserts that deferred accounting is necessary to carry out the purposes of

12              PURA, particularly PURA §§ 36.051, 36.003 and 31.001(c).26 However, ETI has


     24
         In its response to OPC 3-15, ETI stated that it had omitted the transition costs booked to this
     project, which reflects time spent by the SPO Vice President of Strategic Initiatives. The amount is
     shown in WP_G-6 (Set 1).
     25
          Supplemental Direct Testimony of Jay A. Lewis at 4 and Adjustment No. 16.L.
     26
          Id. at 2.

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1             failed to demonstrate that deferred accounting is necessary to allow it to carry out

2             these statutory provisions. There is no indication that deferred accounting treatment

3             is necessary for ETI to earn a reasonable return on its invested capital in excess of

4             its reasonable and necessary operating expense or that it would prevent ETI from

5             having just and reasonable rates.      Further, there is no evidence that a lack of

6             deferred accounting treatment for ETI would somehow prevent Entergy from

7             pursuing its MISO proposal.

8                     Further, ETI has incurred other similar costs to carry out various purposes of

9             PURA without deferred accounting. Since 2005, ETI has spent nearly $20 million

10            pursuing various similar activities including transitioning to competition, investigating

11            RTO options, examining changes to the Entergy System Agreement, and supporting

12            the Entergy Open Access Transmission tariff.27 The table below lists some of the

13            more recent Commission proceedings involving various PURA requirements.                In

14            none of these cases was deferred accounting requested.

                                     Table 4: Entergy Matters
                            Pertaining to Various PURA Requirements
                   Project/                     Description
                   Docket No.
                     32217  Entergy Gulf States Inc.'s Plan For Identifying
                              Applicable Power Region Pursuant To PURA
                              39.452(f)
                      33687     Entergy Texas, Inc.'s Transition to Competition Plan
                      38662     Informational Project Relating To Filings By Entergy
                                 Texas At The Arkansas Public Service Commission
                                 Relating To The Entergy System Agreement And
                                 Possible Successor Arrangements



     27
          ETI’s Response to TIEC 5-10, Addendum 1.

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                                      Table 4: Entergy Matters
                             Pertaining to Various PURA Requirements
                      38663  Informational Project Relating To Filings By Entergy
                               Texas At The Louisiana Public Service Commission
                               Relating To The Entergy System Agreement And
                               Possible Successor Arrangements
                      38708      Project To Investigate The Entergy Successor
                                  Arrangement
                      37344      Information Related To The Entergy Regional State
                                  Committee
                      37378      Commission Review Of Wholesale Market Issues
                                  Relating To Entergy Texas, Inc.

1    Q         WHY ELSE SHOULD ETI’S PROPOSED DEFERRED ACCOUNTING REQUEST

2              BE DENIED?

3    A         The projected transition costs are not material. ETI is currently projecting to incur

4              $17 million of transition costs.28 This equates to only $5.8 million per year, which is

5              only 1% of ETI’s Test Year operating revenues.         Even at this level, the MISO

6              transition costs are easily subsumed in the normal variation in ETI’s year-to-year

7              expenses, as shown in Exhibit JP-8.


8    Q         PLEASE EXPLAIN EXHIBIT JP-8.

9    A         Exhibit JP-8 measures the year-to-year variation in operating expenses booked to

10             those FERC Accounts in which ETI is proposing to record the MISO transition costs.

11             The year-to-year variation is calculated for 3 separate time periods:

12                    1. Calendar year 2009 versus year 2008;
13                    2. Calendar year 2010 versus year 2009; and
14                    3. Docket No. 39896 versus Docket No. 37744.


     28
          Supplemental Direct Testimony of Jay Lewis at 5.

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1        As can be seen, ETI’s expenses in each of these time periods have varied by

2        significantly greater than $5.8 million per year, which is the average amount of MISO

3        transition costs that would be incurred over the next three years. Thus, these costs

4        are immaterial and will not have a significant impact on ETI’s earned rates of return.

5        Therefore, deferred accounting is not required to allow ETI to maintain its financial

6        integrity.


7    Q   SHOULD ETI’S ALTERNATIVE TO DEFERRED ACCOUNTING BE ADOPTED?

8    A   No. The alternative proposal (i.e., $4 million adjustment) would allow ETI to recover

9        primarily expenditures that did not occur during the Test Year. Further, as discussed

10       later, these costs are not known and measurable. Thus, ETI’s alternative treatment

11       would not comport with accepted ratemaking practices, which require setting rates to

12       recover operating expenses based on an historical Test Year adjusted for known and

13       measurable changes.


14   Q   WHY ELSE WOULD ETI’S ALTERNATIVE PROPOSAL BE UNREASONABLE?

15   A   The estimated amount of transition costs is at best uncertain. Highlighting the

16       uncertainty is that ETI’s own estimate of its share of transition costs has drastically

17       changed. When ETI filed its request for deferred accounting in Docket No. 39741, it

18       estimated transition costs of $12 million. Now it is estimating $17 million. Thus, in

19       the span of only three months (which is the length of time between the filing in

20       Docket No. 39741 and this rate case), the estimated costs have increased by over

21       40%.



                                                               2. Revenue Requirement Issues

                                         J.POLLOCK
                                         INCORPORATED
                                                                               Jeffry Pollock
                                                                               Direct Testimony
                                                                               Page 50



1                      Further, ETI is basing its share of the estimated transition costs on the

2               assumption of a 17% responsibility ratio.29 However, as previously stated, ETI’s

3               future responsibility ratios are not known and measurable beyond the Test Year.

4               This is because they are based on projected growth rates of ETI relative to the

5               corresponding growth rates of the other Entergy Operating Companies. Thus, even

6               if the precise amounts of transition costs were known on a system-wide basis, ETI’s

7               share cannot be appropriately measured because it would depend upon the actual

8               responsibility ratios, which in turn depend upon post Test Year load growth.


9    Q          WHAT IS YOUR RECOMMENDATION?

10   A          The Commission should reject ETI’s deferred accounting request because it is

11              clearly not necessary to allow ETI to carry out the purposes of PURA. No similar

12              treatment has been afforded to other expenses incurred to carry out the purposes of

13              PURA, and the expenditures are minimal.        Thus, they will not jeopardize ETI’s

14              financial integrity. Further, the Commission should not allow ETI to recover more

15              than the actual Test Year expenses incurred in making the transition. For all of these

16              reasons, the Commission should allow ETI to recover only Test Year transition costs,

17              or approximately $997,600.




     29
          Id. at 6.

                                                                      2. Revenue Requirement Issues

                                                J.POLLOCK
                                                INCORPORATED
                                                                          Jeffry Pollock
                                                                          Direct Testimony
                                                                          Page 51




                          3. CLASS COST-OF-SERVICE STUDY


1    Q   WHAT IS A CLASS COST-OF-SERVICE STUDY?

2    A   A cost-of-service study is an analysis used to determine each class’s responsibility

3        for the utility’s costs. Thus, it determines whether the revenues a class generates

4        cover the class’s cost-of-service. A class cost-of-service study separates the utility's

5        total costs into portions incurred on behalf of the various customer groups. Most of a

6        utility's costs are incurred to jointly serve many customers. For purposes of rate

7        design and revenue allocation, customers are grouped into homogeneous classes

8        according to their usage patterns and service characteristics. The procedures used

9        in a cost-of-service study are described in more detail in Appendix C.


10   Q   HAVE YOU REVIEWED THE CLASS COST-OF-SERVICE STUDY FILED BY ETI

11       IN THIS PROCEEDING?

12   A   Yes.


13   Q   DOES ETI’S CLASS COST-OF-SERVICE STUDY COMPORT WITH ACCEPTED

14       INDUSTRY PRACTICES?

15   A   Yes, with a few exceptions. ETI’s class cost-of-service recognizes the different types

16       of costs as well as the different ways electricity is used by various customers.


17   Q   IN WHAT WAYS IS ETI’S PROPOSED COST-OF-SERVICE STUDY FLAWED?

18   A   ETI’s class cost-of-service study is flawed in two respects. First, ETI improperly

19       allocated municipal franchise fees (MFF) to customer classes. Second, ETI


                                                                 3. Class Cost-of-Service Study

                                          J.POLLOCK
                                          INCORPORATED
                                                                                Jeffry Pollock
                                                                                Direct Testimony
                                                                                Page 52



1           improperly allocated miscellaneous gross receipts taxes (MGRT) to customer

2           classes. These expenses were allocated on total revenues. This is not consistent

3           with cost causation because MFF are caused by kWh sales within cities that levy

4           MFF, and MGRT are caused by revenues collected by ETI from within cities. They

5           are not caused by total revenues.30


6    Q      SHOULD ETI’S CLASS COST-OF-SERVICE STUDY BE REVISED TO REFLECT

7           THE FLAWS NOTED ABOVE?

8    A      Yes.    The allocations of MFF and MGRT should also be revised to reflect cost

9           causation. I suggest changes to the class cost-of-service to address the appropriate

10          allocation of MFF and MGRT.

11   Municipal Franchise Fees

12   Q      WHAT ARE MUNICIPAL FRANCHISE FEES?

13   A      MFF are taxes levied by municipalities based on the amount of electricity sold within

14          the municipal boundaries. They are also referred to as street rental taxes. The MFF

15          charged to ETI are based on ordinances passed by the elected representatives of

16          the cities in which ETI makes retail sales. Different cities have enacted different

17          levels of MFF on in-city kWh sales ranging from 0.0956¢ to as much as 0.2644¢ per

18          kWh as shown in Exhibit JP-9, pages 1-2.




     30
        I am not addressing a third flaw: the failure to classify any distribution network investment as
     customer-related. The reasons for doing so are discussed in Appendix C.

                                                                       3. Class Cost-of-Service Study

                                               J.POLLOCK
                                               INCORPORATED
                                                                             Jeffry Pollock
                                                                             Direct Testimony
                                                                             Page 53



1    Q      DO THE RATES SHOWN IN EXHIBIT JP-9 REFLECT THE ENTIRETY OF THE

2           MUNICIPAL FRANCHISE FEES CHARGED BY CITIES IN ETI’S SERVICE AREA

3           FOR ?

4    A      No. The rates shown in Exhibit JP-9, pages 1-2 are those MFF collected in base

5           rates. Nineteen cities also charge MFF through separate “Incremental Franchise

6           Fee Recovery” Riders. These incremental MFF are not included in ETI’s proposed

7           revenue requirements in this case.


8    Q      HOW IS ETI PROPOSING TO ALLOCATE MUNICIPAL FRANCHISE FEES

9           RECOVERED IN BASE RATES?

10   A      ETI is proposing to allocate that portion of MFF to be collected in base rates relative

11          to revenues.31


12   Q      IS ETI’S APPROACH CONSISTENT WITH COST CAUSATION?

13   A      No. MFF are not caused by total revenues. MFF are caused by the kWh delivered

14          within incorporated municipalities that levy MFF costs, pursuant to PURA § 33.008.


15   Q      DO CUSTOMERS LOCATED OUTSIDE OF A CITY HAVE ANY CONTROL OVER

16          THE AMOUNT OF MUNICIPAL FRANCHISE FEES THAT A CITY MAY CHARGE?

17   A      No. Unlike in-city customers who can vote on the representatives who set the MFF

18          rates, customers located outside a city have no control over the level of the tax.




     31
         Schedule P-13, page 10, lines 32-33; the allocation factor “RSRRTOA-Total” is rate schedule
     revenue.

                                                                    3. Class Cost-of-Service Study

                                             J.POLLOCK
                                             INCORPORATED
                                                                            Jeffry Pollock
                                                                            Direct Testimony
                                                                            Page 54



1    Q      DO ELECTRICITY SALES OR REVENUES TO CUSTOMERS LOCATED

2           OUTSIDE OF A CITY AFFECT THE AMOUNT OF MUNICIPAL FRANCHISE FEES

3           THAT ETI IS OBLIGATED TO PAY?

4    A      No. Electricity sales to and revenues from customers located outside of a city do not

5           have any effect on how much ETI must pay to the city. Rather, the MFF incurred by

6           ETI is directly caused by in-city kWh sales.


7    Q      IS ETI’S PROPOSED ALLOCATION OF BASE RATE MUNICIPAL FRANCHISE

8           FEES CONSISTENT WITH THE INCREMENTAL FRANCHISE FEE RECOVERY

9           RIDERS?

10   A      No. For example, a typical Incremental Franchise Fee Recovery Rider states:

11                  The rate associated with this Surcharge Tariff shall be $0.0010137 for
12                  every kilowatt-hour billed by the Company to its retail customers
13                  inside the city limits of Beaumont.32 (emphasis added)

14          Thus, incremental franchise fees are allocated and collected solely from retail

15          customers within city limits. This is clearly different from how ETI allocates the

16          portion of MFF that it recovers in base rates, which is based on revenue.


17   Q      DOES THIS COMMISSION HAVE A CONSISTENT POLICY REGARDING THE

18          ALLOCATION OF MUNICIPAL FRANCHISE FEES?

19   A      Yes. The Commission’s current policy was adopted in the unbundled cost-of-service

20          (UCOS) cases in 2001 and affirmed in all delivery rate cases since. Under this

21          policy, MFF costs are allocated based on the classes within the assessing


     32
        Entergy Texas, Inc., Section III Rate Schedule, Incremental Beaumont Franchise Fee Recovery
     Rider, Sheet No. 64, Revision 1 at 101.

                                                                    3. Class Cost-of-Service Study

                                             J.POLLOCK
                                            INCORPORATED
                                                                              Jeffry Pollock
                                                                              Direct Testimony
                                                                              Page 55



1           municipality’s boundaries. This approach is referred to as the “Direct” method of

2           allocation.

3                   Although Commission policy varied widely prior to the UCOS cases (some

4           utilities were allowed to recover MFF separately from in-city customers and others

5           allocated MFF relative to total revenues), the Commission has consistently approved

6           the Direct method of allocation in cases over the past eleven years. This issue was

7           litigated in both the Reliant Energy (now CenterPoint Energy) and TXU (now Oncor)

8           cases. Specifically, the Commission’s Orders in the two cases included the following

9           identical findings:

10                  The LGRT legislation requires the tax be based on the number of
11                  kWh delivered within the municipal boundaries in order to maintain
12                  sufficient revenue levels for the cities. To meet this revenue
13                  requirement, LGRT should be allocated using a direct allocation
14                  and employing the energy allocator.33

15          This same Direct method of allocating MFF was also adopted in Docket Nos. 28840

16          and 33309.


17   Q      HOW SHOULD MFF EXPENSE BE ALLOCATED?

18   A      Consistent with the ratemaking principle of cost causation and Commission

19          precedent, MFF should be allocated using the Direct method, while also recognizing

20          the widely varying MFF rates and class sales by city. The results of this allocation

21          are shown in Exhibit JP-9.

     33
        Application of TXU Electric Company for Approval of Unbundled Cost of Service Rate Pursuant to
     PURA § 39.201 and Public Utility Commission Substantive Rule § 25.344, Docket No. 22350, Order
     at FOF 156 (Oct. 4, 2001); Application of Reliant Energy HL&P for Approval of Unbundled Cost of
     Service Rate Pursuant to PURA § 39.201 and Public Utility Commission Substantive Rule § 25.344,
     Docket No. 22355, Order at FOF 222A (Oct. 4, 2001). Note: the term LGRT, or local gross receipts
     tax, was used synonymously with MFF.

                                                                      3. Class Cost-of-Service Study

                                              J.POLLOCK
                                              INCORPORATED
                                                                          Jeffry Pollock
                                                                          Direct Testimony
                                                                          Page 56



1    Q   PLEASE EXPLAIN EXHIBIT JP-9.

2    A   The starting point for applying the Direct method is the current base rate MFF rates

3        shown in pages 1-2 and the kWh sales by customer class by city shown on pages 3-

4        4. As can be seen, there is no uniformity in both the MFF rates (pages 1-2) and the

5        proportion of kWh sales by class (pages 3-4) by city.         In general, those cities

6        charging the lowest MFF rates also have a larger amount of kWh sales from

7        Schedule LIPS customers. Cities with higher MFF rates generally have a larger

8        proportion of kWh sales from residential customers.

9               The allocated MFF expense is the product of the MFF rates and the

10       corresponding kWh sales by class by city. This calculation is shown in Exhibit JP-9,

11       pages 5-6. The MFF allocation factor is shown on page 6, line 70. It is the result of

12       summing the allocated MFF expenses (line 69) and expressing the total by class

13       (columns 1-6) as a percent of total retail (column 7).


14   Q   IS THE ALLOCATION METHODOLOGY SHOWN IN EXHIBIT JP-9 CONSISTENT

15       WITH COST CAUSATION?

16   A   Yes.   The methodology recognizes that the level of MFF costs ETI incurs is a

17       function of only two things: (1) the tax level set by the city, and (2) the usage of

18       customers inside the city limits. There is nothing that an outside-city customer can

19       do to influence either element. In-city customers, however, determine the tax rate

20       through their elected representatives, and their usage determines the amount that

21       ETI must pay the cities. It also recognizes that MFF rates and the proportion of kWh

22       sales by class are not uniform by city. Customers should only be charged for the


                                                                  3. Class Cost-of-Service Study

                                          J.POLLOCK
                                          INCORPORATED
                                                                                Jeffry Pollock
                                                                                Direct Testimony
                                                                                Page 57



1           MFF they cause. For this reason, it would not be appropriate to charge all customers

2           the same average MFF rate when the rates for many cities (that also happen to

3           serve more Schedule LIPS kWh sales) are below average.


4    Q      HOW SHOULD MFF BE COLLECTED?

5    A      Consistent with cost causation, MFF expense should be recovered from customers

6           located within the municipalities that levy these taxes. This is referred to as the

7           “Direct” method of collection. The Direct method would continue the link between the

8           usage of a group of customers and the costs incurred.             Allocating MFF to and

9           collecting MFF from customers within the cities that levy such taxes is the only way

10          to remain consistent with the principle of cost causation. Thus, customers located

11          outside of tax-levying municipalities should pay zero MFF.


12   Q      IS THERE ANY PRECEDENT FOR THE DIRECT METHOD OF COLLECTING

13          MFF?

14   A      Yes. As previously stated, several cities in ETI’s service area have implemented

15          Incremental Franchise Fee Recovery Riders that collect MFF only from retail

16          customers in the city limits. Further, both Southwestern Public Service Company

17          and Texas New Mexico Power Company use the Direct method in collecting MFF

18          from transmission level customers.34




     34
         Southwestern Public Service, Electric Tariff, Large General Service – Transmission, Section No.
     IV, Sheet No. IV-108, Revision No. 7 at 1; Texas-New Mexico Power Company, Tariff for Retail
     Delivery Service, 6.1.1.1.5 Transmission Service, Revision 5 at 100.

                                                                       3. Class Cost-of-Service Study

                                               J.POLLOCK
                                               INCORPORATED
                                                                             Jeffry Pollock
                                                                             Direct Testimony
                                                                             Page 58




1    Q   WOULD IT BE EQUITABLE TO CHARGE MUNICIPAL FRANCHISE FEES TO

2        CUSTOMERS WHO TAKE SERVICE OUTSIDE CITY LIMITS?

3    A   No. This would be tantamount to “taxation without representation.” Outside-city

4        customers have no voice in determining either the level of MFF, or how the money is

5        to be spent. By spreading MFF to all customers, cities that elect to raise the MFF

6        rate would be able to force outside-city customers to pay for local expenses from

7        which the customers receive no direct benefit. And by cushioning the impact on in-

8        city residents, there would be little to prevent a city from raising its fees. Thus,

9        charging MFF to outside-city customers is not only inequitable, it would weaken the

10       incentive for cities (and city voters) to exercise appropriate fiscal discipline.


11   Q   HAS THIS ISSUE ALSO BEEN ADDRESSED IN OTHER STATES?

12   A   Yes. Regulators in several other states where municipalities levy such taxes have

13       addressed this issue in contested cases and have ordered that MFF be allocated to,

14       and collected from, the customers located inside the levying cities. These states

15       include: Alaska, Arkansas, Colorado, Florida, Idaho, Illinois, Indiana, Iowa, Kansas,

16       Missouri, Nevada, New Mexico, Pennsylvania, Virginia, Washington and West

17       Virginia. Thus, this approach has gained wide acceptance.


18   Q   HOW DO YOU RECOMMEND THAT MFF BE ALLOCATED AND COLLECTED?

19   A   I recommend the Direct method of allocation and the Direct method of collection (i.e.,

20       Direct/Direct) because this method is more consistent with cost causation.




                                                                    3. Class Cost-of-Service Study

                                           J.POLLOCK
                                           INCORPORATED
                                                                             Jeffry Pollock
                                                                             Direct Testimony
                                                                             Page 59



1    Miscellaneous Gross Receipts Taxes

2    Q         WHAT ARE MISCELLANEOUS GROSS RECEIPTS TAXES?

3    A         Miscellaneous gross receipts taxes (MGRT) are state taxes imposed on each utility

4              company’s taxable gross receipts derived from sales in an incorporated city or town

5              having a population of more than 1,000 according to the last Federal census

6              preceding the filing of the report.35 Thus, like MFF, MGRT are levied only on inside-

7              city sales.


8    Q         HOW IS ETI PROPOSING TO ALLOCATE MGRT IN THIS PROCEEDING?

9    A         ETI is proposing to allocate MGRT to all retail customer classes based on

10             revenues.36


11   Q         IS ETI’S APPROACH CONSISTENT WITH COST CAUSATION?

12   A         No. MGRT are not caused by total revenues. MGRT are caused by taxable receipts

13             (i.e., revenues) from business done inside incorporated municipalities. The tax rate

14             is based on the population of the cities.


15   Q         HOW SHOULD MISCELLANEOUS GROSS RECEIPTS TAXES BE ALLOCATED?

16   A         MGRT should be allocated relative to inside-city revenues as shown in Exhibit JP-

17             10. Like my recommendation for MFF, I recommend the Direct method of allocation

18             and the Direct method of collection (i.e., Direct/Direct) because this method is more

19             consistent with cost causation.



     35
          TEX. TAX. CODE ANN. § 182.022(a) (Vernon 2009).
     36
          Schedule P-13, page 10, line 34.

                                                                     3. Class Cost-of-Service Study

                                                 J.POLLOCK
                                                 INCORPORATED
                                                                                     Jeffry Pollock
                                                                                     Direct Testimony
                                                                                     Page 60



1    Revised Class Cost-of-Service Study

2    Q    WHAT IS THE IMPACT OF YOUR RECOMMENDED ALLOCATIONS OF

3         MUNICIPAL FRANCHISE FEES AND MISCELLANEOUS GROSS RECEIPTS

4         TAXES?

5    A    Residential, large industrial power service and lighting customers are all allocated a

6         disproportionately large share of these expenses in ETI’s class cost-of-service study.

7         Correcting these allocations would reduce the costs allocated to these classes.


8    Q    HAVE YOU REVISED ETI’S CLASS COST-OF-SERVICE STUDY TO CORRECT

9         THE ALLOCATIONS OF MUNICIPAL FRANCHISE FEES AND MISCELLANEOUS

10        GROSS RECEIPT TAXES?

11   A    Yes. Exhibit JP-11 is a summary of the revised cost-of-service study reflecting the

12        above changes. It was modeled after ETI’s class cost-of-service study, which is filed

13        in Schedule P. The results are summarized below.

                     Table 5: Summary of Revised Cost-of-Service Study
                                                  Relative Required
                                           Rate
                                                   Rate      Non-Fuel
                     Rate Class             Of                          Percent
                                                     Of      Increase
                                          Return*
                                                  Return* ($ Millions)
           Residential Service            12.25%     83        $80,390   21.2%
           Small General Service          15.30%    104             283   1.1%
           General Service                16.18%    110           9,797   6.1%
           Large General Service          14.82%    101           8,714  17.6%
           Large Industrial Power Service 26.05%    177           9,862   9.5%
           Lighting Service                4.45%     30           2,143  19.8%
           Texas Retail                   14.69%    100       $111,189   15.2%
           * The rates of return do not include purchased power capacity costs. These costs are
           reflected in the required non-fuel (dollar and percent) increases.




                                                                           3. Class Cost-of-Service Study

                                                J.POLLOCK
                                                INCORPORATED
                                                                          Jeffry Pollock
                                                                          Direct Testimony
                                                                          Page 61



1    Q   PLEASE EXPLAIN HOW THE COST-OF-SERVICE STUDY RESULTS ARE

2        MEASURED.

3    A   Rate of return (ROR) is the ratio of net operating income (revenues less allocated

4        operating expenses) to the allocated rate base.          Net operating income is the

5        difference between operating revenues at current rates and allocated operating

6        expenses. If a class is presently providing revenues sufficient to recover its cost-of-

7        service (at the current system rate of return), it will have a rate of return equal to or

8        greater than the total system return of 14.69%.

9                Relative rate of return (RROR) is the ratio of each class’s rate of return to the

10       Texas retail average rate of return. A relative rate of return above 100 means that a

11       class is providing a rate of return higher than the system average, while a relative

12       rate of return below 100 indicates that a class is providing a below-system average

13       rate of return.

14               The required increase is the base revenue change required to move each

15       class to cost. The amounts include the costs reflected in the revised class cost-of-

16       service study as well as the costs that ETI had proposed to collect in Rider PPR.


17   Q   WHAT       DO     THE     REVISED       COST-OF-SERVICE           STUDY       RESULTS

18       DEMONSTRATE?

19   A   There are wide disparities between customer classes. The wide disparity in relative

20       rates of return shows that some classes are providing base revenues that are well

21       below cost, while others are providing revenues well above actual cost. Generally,

22       below-cost classes are being subsidized and should receive above-average


                                                                  3. Class Cost-of-Service Study

                                          J.POLLOCK
                                          INCORPORATED
                                                            Jeffry Pollock
                                                            Direct Testimony
                                                            Page 62



1   increases, while above-cost classes are subsidizing other classes and should

2   receive below-average increases.




                                                    3. Class Cost-of-Service Study

                                  J.POLLOCK
                                  INCORPORATED
                                                                         Jeffry Pollock
                                                                         Direct Testimony
                                                                         Page 63




                             4. CLASS REVENUE ALLOCATION


1    Q   WHAT IS CLASS REVENUE ALLOCATION?

2    A   Class revenue allocation is the process of determining how any base revenue

3        change approved by the Commission should be spread to each customer class

4        served by the utility.


5    Q   HOW SHOULD ANY CHANGE IN BASE REVENUES APPROVED IN THIS

6        DOCKET BE SPREAD AMONG THE VARIOUS CUSTOMER CLASSES SERVED

7        BY ETI?

8    A   Base rate revenues should reflect the actual cost of providing service as closely as

9        practical.   As a general rule, rates should be set at cost.     However, regulators

10       sometimes limit the immediate movement to cost based on gradualism concerns and

11       rate administration. Gradualism is a concept that is applied to prevent a class from

12       receiving an overly-large rate increase. That is, the movement to cost-of-service

13       should be made gradually rather than all at once. Rate administration is a concept

14       that applies when the design of a rate may be tied to the design of other rates.


15   Q   WHY SHOULD THE RESULTS OF THE COST-OF-SERVICE STUDY BE THE

16       PRIMARY FACTOR IN DETERMINING HOW ANY BASE REVENUE CHANGE

17       SHOULD BE ALLOCATED?

18   A   Cost-based rates will send the proper price signals to customers. The other reasons

19       for adhering to cost-of-service principles are equity, engineering efficiency (cost-

20       minimization), stability and conservation.

                                                                   4. Class Revenue Allocation

                                          J.POLLOCK
                                          INCORPORATED
                                                                          Jeffry Pollock
                                                                          Direct Testimony
                                                                          Page 64



1    Q   WHY ARE COST-BASED RATES EQUITABLE?

2    A   Rates which primarily reflect cost-of-service considerations are equitable because

3        each customer pays what it actually costs the utility to serve the customer – no more

4        and no less. If rates are not based on cost, then some customers must pay part of

5        the cost of providing service to other customers, which is inequitable.


6    Q   HOW DO COST-BASED RATES PROMOTE ENGINEERING EFFICIENCY?

7    A   With respect to engineering efficiency, when rates are designed so that demand and

8        energy charges are properly reflected in the rate structure, customers are provided

9        with the proper incentive to minimize their costs which will, in turn, minimize the costs

10       to the utility.


11   Q   HOW CAN COST-BASED RATES PROVIDE STABILITY?

12   A   When rates are closely tied to cost, the utility's earnings are stabilized because

13       changes in customer use patterns result in parallel changes in revenues and

14       expenses. If rates are not based on cost, then an increase in usage by subsidized

15       classes or a decrease in usage by classes providing subsidies will adversely affect

16       the utility’s earnings.


17   Q   HOW DO COST-BASED RATES ENCOURAGE CONSERVATION?

18   A   By providing balanced price signals against which to make consumption decisions,

19       cost-based rates encourage conservation (of both peak day and total usage), which

20       is properly defined as the avoidance of wasteful or inefficient use (and not just less

21       use). If rates are not based on a class cost-of-service study, then consumption


                                                                    4. Class Revenue Allocation

                                          J.POLLOCK
                                          INCORPORATED
                                                                               Jeffry Pollock
                                                                               Direct Testimony
                                                                               Page 65



1           choices are distorted.      ETI’s class cost-of-service study, with the amendments

2           discussed herein, should be used to set rates in this proceeding.


3    Q      DOES THE COMMISSION’S STATED POLICY SUPPORT THE MOVEMENT OF

4           UTILITY RATES TOWARD ACTUAL COST?

5    A      Yes.     The Commission’s support for cost-based rates is longstanding and

6           unequivocal. For example, in a prior AEP Texas Central Company delivery rate

7           case, for example, the Commission found that:

 8                  283. If TCC’s rates are changed, then the T&D rates charged to
 9                  each customer class should move to cost of service. Therefore,
10                  the Commission declines to adopt gradualism in this case.37

11          More recently, the Commission reaffirmed CenterPoint’s proposal to use cost

12          causation principles in its class cost-of-service study and align revenues for each

13          class equal to the allocated costs:

14                  175. In allocating costs, CenterPoint followed the principles of cost
15                  causation. Each of the retail delivery classes has been allocated
16                  revenues in line with the costs those classes generate.38

17          Therefore, moving ETI’s rates to cost is consistent with Commission policy.


18   Q      HAVE YOU REVIEWED ETI’S PROPOSED CLASS REVENUE ALLOCATION?

19   A      Yes. Exhibit JP-12 shows how ETI is proposing to allocate the proposed revenue

20          increase. For purposes of this analysis I have combined the impact of the proposed

21          riders with the proposed base rate increases.

     37
        Application of AEP Texas Central for Authority to Change Rates, Docket No. 28840, Order at 50
     (Aug. 15, 2005).
     38
       Application of CenterPoint Electric Delivery Company, LLC, for Authority to Change Rates, Docket
     No. 38339, Order at 33 (May 12, 2011).

                                                                         4. Class Revenue Allocation

                                              J.POLLOCK
                                              INCORPORATED
                                                                        Jeffry Pollock
                                                                        Direct Testimony
                                                                        Page 66



1    Q   HAVE YOU DEVELOPED A CLASS REVENUE ALLOCATION BASED ON THE

2        RESULTS OF YOUR REVISED JURISIDICTIONAL AND CLASS COST-OF-

3        SERVICE STUDIES?

4    A   Yes. My proposed class revenue allocation is shown in Exhibit JP-13. Page 1

5        assumes no other rate design changes. Page 2 assumes that my recommended

6        designs of Schedules AFC and SMS are adopted. These changes are discussed in

7        Part 5 of my testimony.

8                The non-fuel revenue increases are consistent with the revised class cost-of-

9        service study presented in Exhibit JP-11.      Specifically, those classes receiving

10       above-average non-fuel increases are currently providing below-average rates of

11       return, while those classes receiving below-average non-fuel increases are currently

12       providing above-average rates of return. This is consistent with moving all rates to

13       cost.


14   Q   HOW WOULD YOUR RECOMMENDED CLASS REVENUE ALLOCATION

15       CHANGE IF YOUR RECOMMENDED RATE DESIGN CHANGES ARE ADOPTED?

16   A   As discussed later, I am recommending lower rates in both Schedules SMS and AFC

17       to better reflect cost causation. This would reduce ETI’s revenues by about $2

18       million. As a result, electric sales revenues would need to be increased by $2 million

19       to offset the reductions in both Schedules SMS and AFC. Exhibit JP-13, page 2

20       accounts for these rate design changes. Specifically, I adjusted the recommended

21       increases on page 1 by the amount of Schedule SMS/AFC revenues that were

22       previously allocated to each class in the class cost-of-service study using the same


                                                                  4. Class Revenue Allocation

                                         J.POLLOCK
                                         INCORPORATED
                                                                          Jeffry Pollock
                                                                          Direct Testimony
                                                                          Page 67



1       allocation factors that ETI used in its class cost-of-service study.


2   Q   HOW SHOULD THE PROPOSED INCREASE BE ALLOCATED IN THE EVENT

3       THAT ETI RECEIVES LESS THAN ITS FULL REQUEST IN THIS PROCEEDING?

4   A   The Commission should direct that rates be set based on cost, as shown in

5       Exhibit JP-13. To the extent that elements of ETI’s rate request are disallowed, the

6       class revenue allocation will be reduced in accordance with how such disallowed

7       cost was allocated to each class.




                                                                    4. Class Revenue Allocation

                                         J.POLLOCK
                                         INCORPORATED
                                                                          Jeffry Pollock
                                                                          Direct Testimony
                                                                          Page 68




                                       5. RATE DESIGN


1    Q    PLEASE DESCRIBE THE RATE DESIGN PROCESS.

2    A    Once the amount of revenue to be collected from each rate class is developed,

3         specific rates must be designed that will properly collect that amount of revenue.


4    Q    WHAT RATE DESIGN ISSUES ARE YOU ADDRESSING?

5    A    I am addressing:

6               Schedule LIPS;
7               Schedule SMS (Standby and Maintenance Service);
8               Schedule AFC (Additional Facilities Charge); and,
9               Fixed Fuel Factor
10   Schedule LIPS
11   Q    PLEASE DESCRIBE THE STRUCTURE OF ETI’S LIPS RATE.

12   A    Schedule LIPS recovers base rates through a seasonally adjusted demand charge

13        (per kW) and a two-step non-fuel energy charge (per kWh). The demand charges

14        are also adjusted (either up or down) to reflect the differences in costs by delivery

15        voltage. There is currently no customer charge.


16   Q    WHAT CHANGES IS ETI PROPOSING TO SCHEDULE LIPS?

17   A    In its initial filing, ETI removed all purchased power capacity costs from base rates

18        and proposed recovering them through a Purchased Power Rider (PPR) as a

19        demand charge. When it did so, the proposed demand charges were increased, but

20        the proposed non-fuel energy charges were substantially reduced. Following the

21        Supplemental Preliminary Order, which removed the PPR from further consideration,

                                                                                  5. Rate Design

                                          J.POLLOCK
                                          INCORPORATED
                                                                                  Jeffry Pollock
                                                                                  Direct Testimony
                                                                                  Page 69



1            ETI rolled these costs back into base rates. The resulting “rebundled” demand and

2            energy charges would increase by about the same percentage.


3    Q       DO YOU AGREE WITH ETI’S PROPOSED CHANGES TO SCHEDULE LIPS?

4    A       No. The current structure of Schedule LIPS does not track costs as derived in ETI’s

5            class cost-of-service study. Specifically:

6                   There is no customer charge, despite the fact that the customer costs
7                    allocated to the LIPS class would translate into a monthly rate of over
8                    $6,000.
 9                  The proposed non-fuel energy charges would recover a significant
10                   amount of demand -related costs.

11   Q       WHAT IS THE BASIS FOR YOUR STATEMENT THAT THE STRUCTURE OF

12           SCHEDULE LIPS DOES NOT TRACK COST?

13   A       Exhibit JP-14 provides an analysis of the costs allocated to the LIPS class

14           separated between demand, customer, and energy components. Also shown are

15           the corresponding per unit costs. As can be seen, production/transmission demand-

16           related costs are $8.47 per kW (line 5). Distribution costs add another $0.99 per kW

17           (line 6). The proposed LIPS demand charges are $7.07 per kW for transmission

18           delivery and an additional $1.82 for distribution service. Thus, the proposed demand

19           charges (given ETI’s requested rate increase) are too low. By contrast, non-fuel

20           energy costs are about 0.226¢ per kWh, while the proposed non-fuel energy charges

21           would average over 0.6¢ (line 9).39 Thus, they are 2.5 times higher than the non-fuel




     39
        Schedule LIPS has a two-step energy charge. The first step applies for energy below 584 kWh
     per kW (i.e., hours use), or up to an 80% (584 ÷ 730) load factor. The second step applies for energy
     above 584 kWh per kW (equal to or greater than an 80% load factor).

                                                                                          5. Rate Design

                                                J.POLLOCK
                                                INCORPORATED
                                                                            Jeffry Pollock
                                                                            Direct Testimony
                                                                            Page 70



1           energy costs based on ETI’s filing.        Finally, as previously stated, there is no

2           customer charge in Schedule LIPS.


3    Q      WHAT IS YOUR RECOMMENDATION?

4    A      First, any increase in Schedule LIPS should be used to create a customer charge.

5           As shown in Exhibit JP-14, a cost-based customer charge would be about $6,050

6           per month (line 8).     An initial customer charge of $6,000 per month would be

7           appropriate. This would collect approximately $5.9 million ($6,000 x 984 bills). Any

8           remaining increase not accounted for by the initial customer charge should be

9           collected in the demand charges.        The non-fuel energy charges should not be

10          changed unless the LIPS class is allocated less than a $5.9 million increase. In that

11          event, the non-fuel energy charges should be decreased. This will gradually correct

12          the imbalance between the below-cost demand charges and above-cost energy

13          charges.40 Further, the delivery voltage adjustment applicable to distribution service

14          should be retained so that the rate better reflects the cost.

15   Schedule SMS

16   Q      WHAT IS SCHEDULE SMS?

17   A      Schedule SMS is applicable to customers that use self-generation to supply a portion

18          of their electricity requirements. These customers contract for either Standby and/or

19          Maintenance power service from ETI to replace capacity or energy normally

20          generated by the customer’s on-site generation.


     40
        Should the LIPS class not receive an increase or if base rates are decreased, the Customer
     charge should be reduced proportionally. Any remaining revenue surplus should be applied to
     reduce the non-fuel energy charges to cost and then to reduce the demand charges.

                                                                                   5. Rate Design

                                             J.POLLOCK
                                             INCORPORATED
                                                                                 Jeffry Pollock
                                                                                 Direct Testimony
                                                                                 Page 71



1    Q          WHAT IS STANDBY POWER?

2    A          Standby (or Backup) power is electric energy or capacity supplied to replace energy

3               or capacity that is unavailable due to an unscheduled or forced outage of the

4               facility.41 Thus, Backup power must be available at any time.


5    Q          WHAT IS MAINTENANCE POWER?

6    A          Maintenance power is electric energy or capacity supplied during a scheduled

7               outage.42


8    Q          ARE BACKUP AND MAINTENANCE POWER THE SAME?

9    A          No. Unlike Backup power, Maintenance power must be arranged on a 24-hour prior

10              notice only during such times and at such locations that, in ETI’s sole opinion, will not

11              result in adversely affecting or jeopardizing firm service to other customers, prior

12              commitments or commitments to other utilities.43 In addition, the customer must

13              make arrangements and schedule Maintenance power in writing in advance, and

14              confirmed in writing by ETI. The Company can also limit requests for Maintenance

15              power and allocate and schedule available service, if requests are made from more

16              than one customer.

17                         Thus, Maintenance power is of a lower quality of service than Backup or

18              standby power. Because the Company can limit the amount of Maintenance power,




     41
          P.U.C. SUBST. R. 25.242(C)(2).
     42
          Id. at (c)(7).
     43
          Entergy Texas, Inc., Tariff, Section III Rate Schedules at 29.2.

                                                                                         5. Rate Design

                                                   J.POLLOCK
                                                   INCORPORATED
                                                                       Jeffry Pollock
                                                                       Direct Testimony
                                                                       Page 72



1        it is more likely that customers will prefer to schedule Maintenance power during the

2        non-summer months.


3    Q   IS ETI PROPOSING TO CHANGE SCHEDULE SMS?

4    A   No.


5    Q   HOW ARE STANDBY AND MAINTENANCE POWER PRICED?

6    A   SMS customers pay a monthly demand (or billing load) charge of $1.12 per kW for

7        Backup power. The corresponding charges for Maintenance power are $1.12 per

8        kW for outages during the summer months (May through October) and $0.84 per kW

9        for outages during the non summer months. Thus, the non-summer month charge is

10       75% of the summer month charge.           Energy is priced under an array of time-

11       differentiated charges, as shown in the table below.

                               Table 6: Current Schedule SMS
                                 Non-Fuel Energy Charges
                                         (¢ per kWh)
                           Delivery Voltage             On-Peak   Off-Peak

                   Distribution (less than 69KV)        3.386¢     0.514¢

                   Transmission (69KV and greater)      2.334¢     0.211¢

12       On-peak hours are from 1:00 p.m. to 9:00 p.m., Monday through Friday of each

13       week, beginning on May 15th and continuing through October 15th. In addition, fuel

14       charges are priced at avoided energy cost as calculated under Schedule LQF.


15   Q   ARE THERE ANY SPECIAL RULES GOVERNING HOW STANDBY SERVICE

16       SHOULD BE PRICED?

17   A   Yes, the Commission’s rules prescribe that:

                                                                               5. Rate Design

                                         J.POLLOCK
                                         INCORPORATED
                                                                                 Jeffry Pollock
                                                                                 Direct Testimony
                                                                                 Page 73



 1                    (A)     Rates for sales to qualifying facilities shall be just and
 2                            reasonable and in the public interest, and shall not
 3                            discriminate against any qualifying facility in comparison to
 4                            rates for sales to other customers served by the electric utility.
 5                            Rates for standby or other supplementary service shall be
 6                            based on the amount of capacity contracted for between the
 7                            qualifying facility and the electric utility, and shall not penalize
 8                            electric utilities that also purchase power from qualifying
 9                            facilities. The need for and cost responsibility for special
10                            equipment or system modifications shall be determined by
11                            application of subchapter I of this chapter.

12                    (B)     Rates for sales that are based on accurate data and consistent
13                            system-wide costing principles shall not be considered to
14                            discriminate against any qualifying facility to the extent that
15                            such rates apply to electric utility’s other customers with similar
16                            load or other cost-related characteristics.44

17             Thus, cost-based standby rates are supposed to recognize system wide costing

18             principles, and they must not be discriminatory.


19   Q         ARE THE CURRENT SCHEDULE SMS PRICES COST-BASED?

20   A         No. Exhibit JP-15 shows the derivation of cost-based Schedule SMS charges. The

21             starting points are ETI’s proposed revenue requirement, class revenue allocation and

22             Schedule LIPS rate design.

23                    Referring to page 1, the SMS demand charges should be $0.82 per kW for

24             delivery at transmission and $2.64 per kW for delivery at distribution. Cost-based

25             energy charges would be as follows:




     44
          P.U.C. SUBST. R. 25.242(K)(1).

                                                                                          5. Rate Design

                                                J.POLLOCK
                                                INCORPORATED
                                                                      Jeffry Pollock
                                                                      Direct Testimony
                                                                      Page 74



                              Table 7: Cost-Based Schedule SMS
                                  Non-Fuel Energy Charges
                                         (¢ per kWh)
                             Delivery Voltage           On-Peak   Off-Peak

                   Distribution (less than 69KV)        0.955¢     0.639¢

                   Transmission (69KV and greater)      0.916¢     0.614¢

1    Q   HOW DID YOU DETERMINE THE COST-BASED DEMAND CHARGES FOR

2        STANDBY SERVICE?

3    A   Cost-based demand charges are derived in Exhibit JP-15 as follows:

                      Table 8: Cost-Based Standby Demand Charges
              Delivery Voltage                      Cost Basis
              Transmission            Schedule LIPS Production/Transmission
                                      Demand-Related Cost x Coincidence Ratio
              Distribution            Schedule LIPS Demand-Related Costs

4        The starting point was the Schedule LIPS production/transmission demand-related

5        costs from Exhibit JP-14 or $7.07 per kW (Exhibit JP-15, line 1). On average, 7%

6        of Schedule SMS billing demand was coincident with ETI’s summer month system

7        peaks. This compares to 74% for Schedule LIPS. Thus the ratio of the SMS to LIPS

8        coincidence factors is 12% (line 2). The definition of coincidence factor and the

9        derivation of the SMS and LIPS coincidence factors are discussed later.        The

10       resulting demand charge for transmission service is $0.82 per kW ($7.07 x 12%).

11       The corresponding SMS distribution demand charge is the sum of the transmission

12       charge and the Schedule LIPS distribution demand charge, or $2.64 per kW ($0.82 +

13       $1.82).




                                                                              5. Rate Design

                                         J.POLLOCK
                                         INCORPORATED
                                                                          Jeffry Pollock
                                                                          Direct Testimony
                                                                          Page 75



1    Q   WHY ARE YOU COMBINING PRODUCTION AND TRANSMISSION COSTS IN

2        DERIVING     A COST-BASED SCHEDULE                SMS DEMAND CHARGE FOR

3        TRANSMISSION DELIVERY?

4    A   Both production and transmission demand-related costs are allocated to customer

5        classes using the average and excess four coincident peak (A&E/4CP) method. This

6        method recognizes that production/transmission plant is sized to meet the diversified

7        summer peak demands of all ETI customers. That is, the 4CP demands are a

8        primary driver of the costs of the power plants, PPAs, and transmission facilities.


9    Q   WHAT IS A COINCIDENCE FACTOR?

10   A   Coincidence factor (CF) is defined as follows:




11       Thus, it measures how much of a customer’s peak demand occurs coincident with

12       the utility’s system peak. A 100 MW class with 7% coincidence factor imposes about

13       7 MW of load coincident with the utility’s system peak. The same size class with an

14       80% load factor imposes 80 MW of load coincident with the utility’s system peak.


15   Q   HOW DO DIFFERENCES IN COINCIDENCE FACTORS AFFECT RATE DESIGN?

16   A   Differences in coincidence factors can have a significant impact on rate design, as

17       illustrated below. There are three customers: Customer 1 has a 60% coincidence

18       factor, Customer 2 has an 80% coincidence factor, and Customer 3 has a 5%

19       coincidence factor.




                                                                                 5. Rate Design

                                          J.POLLOCK
                                          INCORPORATED
                                                                    Jeffry Pollock
                                                                    Direct Testimony
                                                                    Page 76



                         Table 9: Relationship Between
                    Coincidence Factor and Demand Charges
                           Billing or
                              Non-
               Coincident Coincident                 Allocated
                Demand      Demand      Coincidence Demand                    Demand
      Customer    (kW)        (kW)         Factor      Costs                   Charge
         1       1,000       2,000          50%       $10,000                   $5.00
         2       1,000       1,250          80%       $10,000                   $8.00
         3       1,000       20,000         5%        $10,000                   $0.50
                                                                              Allocated
                                                Coincident       Costs
                                                                              Demand
                                                 Demand        Allocated
                                                                                Costs
       Source:           Assumptions                 ÷             on
                                                                                   ÷
                                                  Billing      Coincident
                                                                                Billing
                                                 Demand         Demand
                                                                              Demand

1    Customers 1 and 2 are more typical of Schedule LIPS customers that purchase their

2    entire electricity requirements from ETI (i.e., full requirements service). Customer 3

3    is more typical of Schedule SMS customers that use self generation to supply their

4    electricity needs and purchase electricity only during outages (i.e., partial

5    requirements service).

6           As can be seen, the resulting cost-based demand charge is linearly related to

7    coincidence factor. For example, a cost-based demand charge for Customer 3, the

8    self-generator with the lowest coincidence factor, is $0.50 per kW. This is also the

9    lowest demand charge. The corresponding rate for Customer 1, which has a 50%

10   coincidence factor, is $5.00 per kW. This is ten times higher than the cost-based

11   demand charge for Customer 3.        Stated differently, the coincidence factor ratio

12   between Customer 3 and Customer 1 is 10%. Thus, a cost-based demand charge

13   for Customer 3 is only 10% of the corresponding charge for Customer 1.




                                                                            5. Rate Design

                                     J.POLLOCK
                                     INCORPORATED
                                                                       Jeffry Pollock
                                                                       Direct Testimony
                                                                       Page 77



1    Q   WHAT DOES THIS EXAMPLE DEMONSTRATE?

2    A   The example demonstrates that a cost-based Schedule SMS demand charge should

3        be only 12% of the corresponding demand charge for Schedule LIPS. The 12% ratio

4        is derived in Exhibit JP-16.


5    Q   HOW DID YOU DERIVE THE 12% COINCIDENCE RATIO?

6    A   I analyzed the coincidence factor of Schedule SMS customers over a broad time

7        period to determine the extent in which Standby power demands occurred coincident

8        with ETI’s summer month system peaks. This analysis was for calendar years 2007

9        through 2011. Because standby service is sporadic due to the random nature of

10       forced outages, this should be a broad enough period to determine a representative

11       coincidence factor. As can be seen, the Schedule SMS coincidence factor ranged

12       from 3% to 12%, with an average of 7%. The corresponding Test Year coincidence

13       factor was 9%, which falls within the range. The Schedule LIPS class had a 74%

14       coincidence factor during the Test Year. The ratio of 9% to 74% is 12%.


15   Q   WHY ARE YOU PROPOSING TO DIFFERENTIATE THE STANDBY DEMAND

16       CHARGE BY DELIVERY VOLTAGE?

17   A   Implementing voltage differentials in the demand charge more directly recognizes the

18       different costs to provide service at transmission and distribution voltage. These

19       differences are discussed later. This recommendation is consistent with the current

20       Schedule SMS energy charges.




                                                                              5. Rate Design

                                        J.POLLOCK
                                        INCORPORATED
                                                                       Jeffry Pollock
                                                                       Direct Testimony
                                                                       Page 78



1    Q   WHY HAVE YOU NOT APPLIED THE 12% COINCIDENCE RATIO IN

2        DETERMINING THE DISTRIBUTION-RELATED SCHEDULE SMS DEMAND

3        CHARGE?

4    A   Distribution facilities are electrically closer to customers. Thus, a customer’s peak

5        demand determines how distribution facilities must be sized to ensure reliable

6        service. ETI recognizes this driver by using maximum diversified demand (MDD) to

7        allocate distribution demand-related costs.      For this reason, Schedule SMS

8        customers require the same amount of distribution capacity as a similarly sized

9        Schedule LIPS customer.     Thus, the Schedule SMS distribution demand charge

10       should be the same as the corresponding Schedule LIPS demand charge.


11   Q   HOW DID YOU DERIVE COST-BASED ENERGY CHARGES?

12   A   This is shown in Exhibit JP-15, page 2. The Schedule SMS energy charge should

13       reflect the composite Schedule LIPS energy charges, or 0.614¢ per kWh. During on-

14       peak hours, a Schedule SMS customer should also pay additional demand charges.

15       This recognizes that an SMS customer that purchases more energy during on-peak

16       hours would more closely resemble a LIPS customer.

17              For this reason, cost-based on-peak energy charge should be a composite of

18       the Schedule LIPS energy charge and the remaining demand charges (not collected

19       in the SMS demand charge). The remaining demand charges are derived on Line 3.

20       There are approximately 2,040 on-peak hours in a typical year.          Dividing the

21       remaining demand charges by 2,040 yields an additional on-peak energy charge of

22       0.303¢. This yields a total on-peak energy charge of 0.917¢ (line 9). Under this


                                                                               5. Rate Design

                                         J.POLLOCK
                                        INCORPORATED
                                                                      Jeffry Pollock
                                                                      Direct Testimony
                                                                      Page 79



1        structure, an SMS customer that experiences an outage would pay approximately

2        the same for electricity as a LIPS customer.


3    Q   PLEASE SUMMARIZE YOUR RECOMMENDED SCHEDULE SMS PRICING

4        STRUCTURE.

5    A   Schedule SMS should be reduced to more closely reflect the cost of providing

6        standby service as follows:

                      Table 10a: Cost-Based Schedule SMS Charges
                      Based on ETI’s Proposed Schedule LIPS Design

                                     Distribution          Transmission
                      Charge
                                  (less than 69KV)      (69KV and greater)
                    Billing Load Charge ($/kW):
                    Standby             $2.64                 $0.82
                    Maintenance         $2.44                 $0.62

                    Non-Fuel Energy Charge (¢/kWh)
                    On-Peak          0.955¢                  0.916¢
                    Off-Peak         0.639¢                  0.614¢

7    Q   HAVE YOU DEVELOPED A SCHEDULE SMS RATE DESIGN BASED ON YOUR

8        RECOMMENDED SCHEDULE LIPS DESIGN?

9    A   Yes.   Using my recommended Schedule LIPS rate design, the Schedule SMS

10       charges are shown in the table below. This is based on ETI’s proposed revenue

11       requirements and class revenue allocation.         If the Schedule LIPS revenue

12       requirement is reduced, the charges should be correspondingly reduced. As with my

13       recommended Schedule LIPS rate design, I have added a customer charge. The

14       customer charge should not apply if a Schedule SMS customer is also purchasing

15       supplementary power under another applicable rate. This will avoid over-collecting


                                                                             5. Rate Design

                                         J.POLLOCK
                                         INCORPORATED
                                                                          Jeffry Pollock
                                                                          Direct Testimony
                                                                          Page 80



                     Table 10b: Cost-Based Schedule SMS Charges
                  Based on TIEC’s Recommended Schedule LIPS Design

                                          Distribution         Transmission
                       Charge
                                       (less than 69KV)     (69KV and greater)
                 Customer Charge
                 (Stand-Alone)                          $6,000
                 Billing Load Charge ($/kW):
                 Standby                  $2.46                   $0.79
                 Maintenance              $2.27                   $0.60
                 Non-Fuel Energy Charge (¢/kWh)
                 On-Peak                0.881¢                   0.846¢
                 Off-Peak               0.575¢                   0.552¢

1        customer-related costs. The above recommendations are based on (and consistent

2        with) the use of system wide costing principles.


3    Q   HOW WERE THE MAINTENANCE POWER CHARGES DERIVED?

4    A   I maintained the same relationship; that is, the current Maintenance power demand

5        charge is 75% of the Standby power demand charge. The 75% should apply to the

6        production/transmission component of the recommended Standby power demand

7        charge because distribution costs are caused by maximum demands occurring at

8        any time, as previously discussed. This would result in a $0.20 and $0.19 per kW

9        differential based on ETI’s proposed and my recommended Schedule LIPS designs,

10       respectively. The recommended Maintenance power demand charges reflect the

11       same differential.




                                                                                 5. Rate Design

                                         J.POLLOCK
                                         INCORPORATED
                                                                                     Jeffry Pollock
                                                                                     Direct Testimony
                                                                                     Page 81



1    Q         WOULD YOUR RECOMMENDED COSTING METHODOLOGY APPLIED ABOVE

2              COMPORT WITH THE COMMISSION’S RULES REGARDING THE RATES FOR

3              SALES OF BACKUP AND MAINTENANCE POWER?

4    A         Yes. The Commission’s rules require that:

5                      The rates for sales of Backup or Maintenance power:

 6                     (A)        shall not be based upon an assumption (unless supported by
 7                                factual data) that forced outages or other reductions in electric
 8                                output by all qualifying facilities on an electric utility’s system
 9                                will occur simultaneously, or during the system peak, or both;
10                                and

11                     (B)        shall take into account the extent to which scheduled outages
12                                of the qualifying facilities can be usefully coordinated with
13                                scheduled outages of the utility’s facilities.45

14             My cost analysis comports with the Rule. Specifically, Standby power is seldom

15             provided coincident with ETI’s summer peaks as evidenced by the much lower

16             coincidence factor for Standby power than for requirements service provided in

17             Schedule LIPS. This clearly demonstrates that standby customers are different than

18             full requirements customers and that these differences warrant a different rate for

19             production and transmission services. Further, I have also used system-wide costing

20             principles to derive cost-based energy charges in Schedule SMS.

21   Schedule AFC
22   Q         WHAT IS SCHEDULE AFC?

23   A         Schedule AFC is the mechanism for charging customers for the costs of

24             transformers, breakers and lines directly to customers when those facilities provide

25             service only to specific customers. ETI receives revenues from these customers,

     45
          P.U.C. SUBST. R.   25.242(K)(3).

                                                                                             5. Rate Design

                                                    J.POLLOCK
                                                    INCORPORATED
                                                                         Jeffry Pollock
                                                                         Direct Testimony
                                                                         Page 82



1        which must be accounted for in ETI’s cost study. Some of these facilities are booked

2        to transmission accounts while others are booked to distribution accounts.


3    Q   HOW IS SCHEDULE AFC STRUCTURED?

4    A   Schedule AFC is applied as a percentage of the original (un-depreciated) cost of the

5        facilities. The percentage is supposed to reflect ETI’s costs of owning and operating

6        the direct assigned facilities.

7                There are two separate pricing options.      Under Option A, the charge is

8        currently 1.49% per month. Option B applies when a customer elects to amortize the

9        direct assigned facilities over a shorter term ranging from one to ten years. Thus, the

10       Option B Monthly Recovery Term charge varies depending on the length of the

11       amortization period of the direct assigned investment.      There is also a 0.453%

12       Monthly Post-Recovery term charge that applies after a facility has been fully

13       depreciated.


14   Q   IS ETI PROPOSING TO CHANGE EITHER THE OPTION A OR OPTION B

15       CHARGES IN SCHEDULE AFC?

16   A   No.


17   Q   SHOULD THE OPTION A AND OPTION B CHARGES BE REVISED?

18   A   Yes. The charges in Schedule AFC should be designed to reflect the cost of owning,

19       operating, and maintaining the direct-assigned facilities.     However, the current

20       Option A and Option B charges are well in excess of ETI’s ownership and operation

21       & maintenance (O&M) costs. This is shown in Exhibit JP-17 for Option A and


                                                                                5. Rate Design

                                           J.POLLOCK
                                           INCORPORATED
                                                                          Jeffry Pollock
                                                                          Direct Testimony
                                                                          Page 83



1        Exhibit JP-18 for Option B.      The analysis is summarized on page 1, while the

2        detailed analysis is provided on page 2.


3    Q   PLEASE EXPLAIN EXHIBIT JP-17.

4    A   Exhibit JP-17 provides a cost analysis of the Schedule AFC Option A charges.

5        Referring to page 1, I have used two different methods to derive a cost-based rate:

6                 1. Levelized Cost Analysis (line 1); and

7                 2. Revenue Requirement Analysis (lines 2-4).

8        The levelized cost analysis assumes that an investment and associated costs is

9        recovered ratably over its useful life. This detailed derivation of the levelized cost

10       and the assumed cost parameters are shown on page 2. As can be seen on page 2,

11       the assumed cost parameters are based on ETI’s proposed rate of return (stated on

12       a pre-tax basis to account for income taxes), depreciation rates, O&M expense and

13       property taxes. The levelized cost analysis results in an Option A rate of 1.20% per

14       month.

15                A revenue requirement analysis is derived from a cost-of-service study that

16       shows the overall costs on a functional (i.e., transmission, distribution) basis, such as

17       in Schedules P-5 and P-6.1.2. Specifically, the functionalized revenue requirement

18       (line 2) is expressed as a percent of gross plant investment (line 3). A separate

19       analysis was conducted for transmission and distribution functions because

20       Schedule AFC facilities are booked to both transmission and distribution accounts.

21       The resulting fixed charges are 1.05% for transmission and 1.27% for distribution.

22       Weighting the two functions by the amount of transmission and distribution-related


                                                                                  5. Rate Design

                                          J.POLLOCK
                                          INCORPORATED
                                                                       Jeffry Pollock
                                                                       Direct Testimony
                                                                       Page 84



1        Schedule AFC revenues results in a weighted average rate of 1.18%.


2    Q   PLEASE EXPLAIN EXHIBIT JP-18.

3    A   Cost-based Option B charges are summarized in Exhibit JP-18, page 1.            The

4        detailed analysis is provided on page 2. It uses the same parameters as the Option

5        A cost analysis. The Monthly Recovery Term Charges are based on a levelized cost

6        analysis for each of the Option B amortization periods (lines 1 through 10). The

7        ownership cost components (i.e., return, taxes and depreciation) are also quantified

8        on a levelized basis (columns 1 and 2). They are expressed as a percent of the

9        original investment (column 5). The operating costs (O&M and property taxes) are

10       shown in columns 3 and 4. They are based on the same Test Year parameters used

11       by ETI as shown in Exhibit JP-17, page 2. The Monthly Recovery Term Charges

12       (column 8) are the sum of each of the components (columns 5 through 7). This

13       charge applies until the investment is depreciated. Thereafter, the Post Recovery

14       Term charge applies.


15   Q   WHAT IS YOUR RECOMMENDATION?

16   A   The monthly charges in Schedule AFC should be reduced to reflect the actual cost-

17       of-service established in this proceeding.    The current 1.49% per month charge

18       under Option A is much higher than the actual carrying costs on transmission and

19       distribution investment, which would be 1.20% per month under ETI’s proposed

20       revenue requirements (Exhibit JP-17).     The proposed Option B Recovery Term

21       charges should also be correspondingly lower as shown in Exhibit JP-18. The O&M

22       charge under Option B should be 0.35% per month.

                                                                              5. Rate Design

                                        J.POLLOCK
                                        INCORPORATED
                                                                                  Jeffry Pollock
                                                                                  Direct Testimony
                                                                                  Page 85



1                    If the Commission approves a lower base revenue requirement than ETI has

2          proposed, the recommended Schedule AFC charges (both Option A and Option B)

3          should be reduced in proportion to any authorized reduction in ETI’s proposed rate of

4          return, O&M expense and property tax expense.

5    Fixed Fuel Factor

6    Q     SHOULD ANY CHANGE BE MADE TO THE FIXED FUEL FACTOR?

7    A     Yes. The same loss multipliers have been used in ETI’s Fixed Fuel Factor tariff for

8          many years. This case provides an opportunity to review the appropriateness of

9          these loss multipliers.


10   Q     WHAT IS A LOSS MULTIPLIER?

11   A     A loss multiplier is a factor that restates the system average fuel costs into the

12         corresponding     delivered   fuel    costs   by    voltage   (e.g.,   secondary,   primary,

13         transmission). This recognizes that delivered costs are inversely related to energy

14         losses.    ETI incurs lower energy losses to serve a transmission customer than

15         distribution (primary or secondary) customers. Thus, the distribution loss multipliers

16         are higher than the transmission loss multipliers.

17                   For example, the current Texas retail fuel factor is 4.02739¢ per kWh. A

18         customer taking primary service has a loss multiplier of 1.004911. Consequently, the

19         fixed fuel factor applicable to primary service is the product of the Retail Fixed Fuel

20         Factor and the primary loss multiplier, or 4.04717¢ (4.02739¢ X 1.004911). This

21         compares to 3.87806¢ (4.02739¢ X 0.962921) for a transmission customer taking

22         service up to (but not including) 230 KV.


                                                                                        5. Rate Design

                                                J.POLLOCK
                                                INCORPORATED
                                                                          Jeffry Pollock
                                                                          Direct Testimony
                                                                          Page 86



1    Q   HOW ARE LOSS MULTIPLIERS DERIVED?

2    A   Loss multipliers are based on the energy losses incurred by ETI to deliver electricity

3        at each of the various delivery voltages. The energy losses, in turn, are derived from

4        system loss studies, which analyze the components of the utility’s delivery system to

5        determine the amounts of energy lost in delivering electricity from the generators to

6        customers’ meters.


7    Q   IS A LOSS STUDY USED ELSEWHERE IN DEVELOPING RATES?

8    A   Yes. The same loss study is used to develop both energy losses as well as peak

9        demand losses. Both sets of losses are then used to establish demand and energy

10       allocation factors by customer class. These allocation factors are then used in ETI’s

11       class cost-of-service study to determine each class’s revenue requirements.         A

12       summary of the demand and energy losses is provided in Schedule P-7.2.


13   Q   HOW ARE THE ENERGY LOSSES USED TO DEVELOP A LOSS MULTIPLIER?

14   A   The loss multipliers are derived using the following equation:

                                     DV
15                       LM =
                                     AV


16                Where: EL = Energy Losses
17                       DV = Delivery Voltage
18                       AVG = System Average Energy Losses

19       Applying this equation yields the loss multiplier shown in Exhibit JP-19, columns 1

20       and 2.




                                                                                5. Rate Design

                                          J.POLLOCK
                                          INCORPORATED
                                                                        Jeffry Pollock
                                                                        Direct Testimony
                                                                        Page 87



1    Q   HOW DO THE LOSS MULTIPLIERS DERIVED IN THIS CASE COMPARE WITH

2        THE CURRENT LOSS MULTIPLIERS USED IN ETI’S FIXED FUEL FACTOR?

3    A   The current loss multipliers are shown in column 3 of Exhibit JP-19. As can be

4        seen, the new loss multipliers (column 2) are lower than the current multipliers

5        (column 3). The most obvious change is that for Primary Service, the loss multiplier

6        would decrease from an amount greater than 1.0 to a multiplier slightly below 1.0.


7    Q   WHAT DO YOU RECOMMEND?

8    A   The Fixed Fuel Factor loss multipliers should be revised based on the analysis

9        presented in Exhibit JP-19, column 2. The revised loss multipliers would allow more

10       accurate recovery of fuel costs by delivery voltage and align the cost recovery

11       processes between base rates (which use the same energy losses) and the fuel

12       factor.


13   Q   DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?

14   A   Yes.




                                                                               5. Rate Design

                                         J.POLLOCK
                                         INCORPORATED
                                                                        Jeffry Pollock
                                                                        Direct Testimony
                                                                        Page 88



                                        APPENDIX A

1                              Qualifications of Jeffry Pollock

2    Q   PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.

3    A   Jeffry Pollock. My business mailing address is 12655 Olive Blvd., Suite 335, St.

4        Louis, Missouri 63141.


5    Q   WHAT IS YOUR OCCUPATION AND BY WHOM ARE YOU EMPLOYED?

6    A   I am an energy advisor and President of J. Pollock, Incorporated.


7    Q   PLEASE STATE YOUR EDUCATIONAL BACKGROUND AND EXPERIENCE.

8    A   I have a Bachelor of Science Degree in Electrical Engineering and a Masters in

9        Business Administration from Washington University. I have also completed a Utility

10       Finance and Accounting course.

11                Upon graduation in June 1975, I joined Drazen-Brubaker & Associates, Inc.

12       (DBA).    DBA was incorporated in 1972 assuming the utility rate and economic

13       consulting activities of Drazen Associates, Inc., active since 1937. From April 1995

14       to November 2004, I was a managing principal at Brubaker & Associates (BAI).

15                During my tenure at both DBA and BAI, I have been engaged in a wide range

16       of consulting assignments including energy and regulatory matters in both the United

17       States and several Canadian provinces.         This includes preparing financial and

18       economic studies of investor-owned, cooperative and municipal utilities on revenue

19       requirements, cost of service and rate design, and conducting site evaluation.

20       Recent engagements have included advising clients on electric restructuring issues,



                                                                                  Appendix A

                                         J.POLLOCK
                                         INCORPORATED
                                                                         Jeffry Pollock
                                                                         Direct Testimony
                                                                         Page 89



1        assisting clients to procure and manage electricity in both competitive and regulated

2        markets, developing and issuing requests for proposals (RFPs), evaluating RFP

3        responses and contract negotiation.      I was also responsible for developing and

4        presenting seminars on electricity issues.

5               I have worked on various projects in over 20 states and several Canadian

6        provinces, and have testified before the Federal Energy Regulatory Commission and

7        the state regulatory commissions of Alabama, Arizona, Colorado, Delaware, Florida,

8        Georgia, Indiana, Illinois, Indiana, Iowa, Kansas, Louisiana, Minnesota, Mississippi,

9        Missouri, Montana, New Jersey, New Mexico, New York, Ohio, Pennsylvania, Texas,

10       Virginia, Washington, and Wyoming. I have also appeared before the City of Austin

11       Electric Utility Commission, the Board of Public Utilities of Kansas City, Kansas, the

12       Bonneville Power Administration, Travis County (Texas) District Court, and the U.S.

13       Federal District Court. A partial list of my appearances is provided in Appendix B.


14   Q   PLEASE DESCRIBE J. POLLOCK, INCORPORATED.

15   A   J.Pollock assists clients to procure and manage energy in both regulated and

16       competitive markets.     The J.Pollock team also advises clients on energy and

17       regulatory issues. Our clients include commercial, industrial and institutional energy

18       consumers. Currently, J.Pollock has offices in St. Louis, Missouri and Austin, Texas.

19       J.Pollock is a registered Class I aggregator in the State of Texas.




                                                                                   Appendix A

                                          J.POLLOCK
                                         INCORPORATED
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                                                                     Testimony Filed in Regulatory Proceedings
                                                                                 by Jeffry Pollock


                                                                                                                                              REGULATORY
PROJECT                         UTILITY                             ON BEHALF OF                       DOCKET                TYPE             JURISDICTION                        SUBJECT                             DATE

 91023    ENTERGY TEXAS, INC.                        Texas Industrial Energy Consumers                  39851         Supplemental Rebuttal       TX         Competitive Generation Service Issues                  2/24/2012

 91203    ENTERGY TEXAS, INC.                        Texas Industrial Energy Consumers                  39851          Supplemental Direct        TX         Competitive Generation Service Issues                  2/10/2012

 101101   AEP TEXAS CENTRAL COMPANY                  Texas Industrial Energy Consumers                  39722                Direct               TX         Carrying Charge Rate Applicable to the Additional      11/4/2011
                                                                                                                                                             True-Up Balance and Tax Balances
 110703   GULF POWER COMPANY                         Florida Industrial Power Users Group              110138-EI             Direct                FL        Cost Allocation and Storm Reserve                      10/14/2011

 90404    CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC   Texas Industrial Energy Consumers                  39504                Direct               TX         Carrying Charge Rate Applicable to the Additional      9/12/2011
                                                                                                                                                             True-Up Balance and Taxes
 101101   AEP TEXAS NORTH COMPANY                    Texas Industrial Energy Consumers                  39361            Cross-Rebuttal           TX         Energy Efficiency Cost Recovery Factor                 8/10/2011

 101101   AEP TEXAS CENTRAL COMPANY                  Texas Industrial Energy Consumers                  39360            Cross-Rebuttal           TX         Energy Efficiency Cost Recovery Factor                 8/10/2011

 100503   ONCOR ELECTRIC DELIVERY COMPANY, LLC       Texas Industrial Energy Consumers                  39375                Direct               TX         Energy Efficiency Cost Recovery Factor                  8/2/2011

 90103    ALABAMA POWER COMPANY                      Alabama Industrial Energy Consumers                31653                Direct                AL        Renewable Purchased Power Agreement                    7/28/2011

 101101   AEP TEXAS NORTH COMPANY                    Texas Industrial Energy Consumers                  39361                Direct               TX         Energy Efficiency Cost Recovery Factor                 7/26/2011

 101101   AEP TEXAS CENTRAL COMPANY                  Texas Industrial Energy Consumers                  36360                Direct               TX         Energy Efficiency Cost Recovery Factor                 7/20/2011

 90201    ENTERGY TEXAS, INC.                        Texas Industrial Energy Consumers                  39366                Direct               TX         Energy Efficiency Cost Recovery Factor                 7/19/2011
 90404    CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC   Texas Industrial Energy Consumers                  39363                Direct               TX         Energy Efficiency Cost Recovery Factor                 7/15/2011

 101201   NORTHERN STATES POWER COMPANY              Xcel Large Industrials                         E002/GR-10-971           Direct               MN         Surplus Depreciation Reserve, Incentive                 4/5/2011
                                                                                                                                                             Compensation, Non-Asset Trading Margin Sharing,
                                                                                                                                                             Cost Allocation, Class Revenue Allocation, Rate
                                                                                                                                                             Design

 101202   ROCKY MOUNTAIN POWER                       Wyoming Industrial Energy Consumers            20000-381-EA-10          Direct               WY         2010 Protocols                                         2/11/2011

 100802   TEXAS-NEW MEXICO POWER COMPANY             Texas Industrial Energy Consumers                  38480                Direct               TX         Cost Allocation, TCRF                                  11/8/2010

 90402    GEORGIA POWER COMPANY                      Georgia Industrial Group/Georgia Traditional       31958                Direct               GA         Alternate Rate Plan, Return on Equity, Riders, Cost-of- 10/22/2010
                                                     Manufacturers Group                                                                                     Service Study, Revenue Allocation, Economic
                                                                                                                                                             Development
 90404    CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC   Texas Industrial Energy Consumers                  38339            Cross-Rebuttal           TX         Cost Allocation, Class Revenue Allocation              9/24/2010

 90404    CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC   Texas Industrial Energy Consumers                  38339                Direct               TX         Pension Expense, Surplus Depreciation Reserve, Cost    9/10/2010
                                                                                                                                                             Allocation, Rate Design, Riders

 100303   NIAGARA MOHAWK POWER CORP.                 Multiple Intervenors                              10-E-0050            Rebuttal              NY         Multi-Year Rate Plan, Cost Allocation, Revenue          8/6/2010
                                                                                                                                                             Allocation, Reconciliation Mechanisms, Rate Design

 100303   NIAGARA MOHAWK POWER CORP.                 Multiple Intervenors                              10-E-0050             Direct               NY         Multi-Year Rate Plan, Cost Allocation, Revenue         0714/2010
                                                                                                                                                             Allocation, Reconciliation Mechanisms, Rate Design
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                                                                Testimony Filed in Regulatory Proceedings
                                                                            by Jeffry Pollock


                                                                                                                                  REGULATORY
PROJECT                         UTILITY                        ON BEHALF OF                        DOCKET            TYPE         JURISDICTION                           SUBJECT                             DATE
 91203    ENTERGY TEXAS, INC.                   Texas Industrial Energy Consumers                   37744        Cross Rebuttal       TX         Cost Allocation, Revenue Allocation, CGS Rate             6/30/2010
                                                                                                                                                 Design, Interruptible Service
 91203    ENTERGY TEXAS, INC.                   Texas Industrial Energy Consumers                   37744            Direct           TX         Class Cost of Service Study, Revenue Allocation, Rate      6/9/2010
                                                                                                                                                 Design, Competitive Generation Services, Line
                                                                                                                                                 Extension Policy
 90201    ENTERGY TEXAS, INC.                   Texas Industrial Energy Consumers                   37482        Cross Rebuttal       TX         Allocation of Purchased Power Capacity Costs               2/3/2010

 90402    GEORGIA POWER COMPANY                 Georgia Industrial Group/Georgia Traditional        28945            Direct           GA         Fuel Cost Recovery                                        1/29/2010
                                                Manufacturers Group
 90201    ENTERGY TEXAS, INC.                   Texas Industrial Energy Consumers                   37482            Direct           TX         Purchased Power Capacity Cost Factor                      1/22/2010

 90403    VIRGINIA ELECTRIC AND POWER COMPANY   MeadWestvaco Corporation                        PUE-2009-00081       Direct           VA         Allocation of DSM Costs                                   1/13/2010

 90201    ENTERGY TEXAS, INC.                   Texas Industrial Energy Consumers                   37580            Direct           TX         Fuel refund                                               12/4/2009

 90403    VIRGINIA ELECTRIC AND POWER COMPANY   MeadWestvaco Corporation                        PUE-2009-00019       Direct           VA         Standby rate design; dynamic pricing                      11/9/2009

 80601    SOUTHWESTERN PUBLIC SERVICE COMPANY   Texas Industrial Energy Consumers                   37135            Direct           TX         Transmission cost recovery factor                         10/22/2009

 80703    MID-KANSAS ELECTRIC COMPANY, LLC      Western Kansas Industrial Energy Consumers     09-MKEE-969-RTS       Direct           KS         Revenue requirements, TIER, rate design                   10/19/2009

 90601    VARIOUS UTILITIES                     Florida Industrial Power Users Group              090002-EG          Direct            FL        Interruptible Credits                                     10/2/2009

 80505    ONCOR ELECTRIC DELIVERY COMPANY       Texas Industrial Energy Consumers                   36958        Cross Rebuttal       TX         2010 Energy efficiency cost recovery factor               8/18/2009

 81001    PROGRESS ENERGY FLORIDA               Florida Industrial Power Users Group                90079            Direct            FL        Cost-of-service study, revenue allocation, rate design,   8/10/2009
                                                                                                                                                 depreciation expense, capital structure
 90404    CENTERPOINT                           Texas Industrial Energy Consumers                   36918        Cross Rebuttal       TX         Allocation of System Restoration Costs                    7/17/2009

 90301    FLORIDA POWER AND LIGHT COMPANY       Florida Industrial Power Users Group               080677            Direct            FL        Depreciation; class revenue allocation; rate design;      7/16/2009
                                                                                                                                                 cost allocation; and capital structure
 90201    ENTERGY TEXAS, INC.                   Texas Industrial Energy Consumers                   36956            Direct           TX         Approval to revise energy efficiency cost recovery        7/16/2009
                                                                                                                                                 factor
 90601    VARIOUS UTILITIES                     Florida Industrial Power Users Group           VARIOUS DOCKETS       Direct            FL        Conservation goals                                         7/6/2009

 90201    ENTERGY TEXAS, INC.                   Texas Industrial Energy Consumers                   36931            Direct           TX         System restoration costs under Senate Bill 769            6/30/2009

 90502    SOUTHWESTERN ELECTRIC POWER COMPANY   Texas Industrial Energy Consumers                   36966            Direct           TX         Authority to revise fixed fuel factors                    6/18/2009

 80805    TEXAS-NEW MEXICO POWER COMPANY        Texas Industrial Energy Consumers                   36025        Cross-Rebuttal       TX         Cost allocatiion, revenue allocation and rate design      6/10/2009

 80805    TEXAS-NEW MEXICO POWER COMPANY        Texas Industrial Energy Consumers                   36025            Direct           TX         Cost allocation, revenue allocation, rate design          5/27/2009

 81201    NORTHERN STATES POWER COMPANY         Xcel Large Industrials                             08-1065        Surrebuttal         MN         Cost allocation, revenue allocation, rate design          5/27/2009

 90403    VIRGINIA ELECTRIC AND POWER COMPANY   MeadWestvaco Corporation                        PUE-2009-00018       Direct           VA         Transmission cost allocation and rate design              5/20/2009
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                                                                    Testimony Filed in Regulatory Proceedings
                                                                                by Jeffry Pollock


                                                                                                                                             REGULATORY
PROJECT                         UTILITY                            ON BEHALF OF                       DOCKET                TYPE             JURISDICTION                         SUBJECT                               DATE
 90101    NORTHERN INDIANA PUBLIC SERVICE COMPANY   Beta Steel Corporation                             43526                Direct                IN        Cost allocation and rate design                            5/8/2009

 81203    ENTERGY SERVICES, INC                     Texas Industrial Energy Consumers                ER008-1056            Rebuttal             FERC        Rough Production Cost Equalization payments                5/7/2009

 81201    NORTHERN STATES POWER COMPANY             Xcel Large Industrials                             08-1065             Rebuttal              MN         Class revenue allocation and the classification of         5/5/2009
                                                                                                                                                            renewable energy costs

 81201    NORTHERN STATES POWER COMPANY             Xcel Large Industrials                             08-1065              Direct               MN         Cost-of-service study, class revenue allocation, and       4/7/2009
                                                                                                                                                            rate design

 81203    ENTERGY SERVICES, INC                     Texas Industrial Energy Consumers                ER08-1056              Answer              FERC        Rough Production Cost Equalization payments                3/6/2009

 80901    ROCKY MOUNTAIN POWER                      Wyoming Industrial Energy Consumers            20000-333-ER-08          Direct               WY         Cost of service study; revenue allocation; inverted       1/30/2009
                                                                                                                                                            rates; revenue requirements
 81203    ENTERGY SERVICES                          Texas Industrial Energy Consumers                ER08-1056              Direct              FERC        Entergy's proposal seeking Commission approval to          1/9/2009
                                                                                                                                                            allocate Rough Production Cost Equalization
                                                                                                                                                            payments
 80505    ONCOR ELECTRIC DELIVERY COMPANY &         Texas Industrial Energy Consumers                  35717            Cross Rebuttal           TX         Retail transformation; cost allocation, demand ratchet    12/24/2008
          TEXAS ENERGY FUTURE HOLDINGS LTD                                                                                                                  waivers, transmission cost allocation factor

 70101    GEORGIA POWER COMPANY                     Georgia Industrial Group and Georgia               27800                Direct               GA         Cash Return on CWIP associated with the Plant Vogtle 12/19/2008
                                                    Traditional Manufacturers Association                                                                   Expansion
 80505    ONCOR ELECTRIC DELIVERY COMPANY &         Texas Industrial Energy Consumers                  35717                Direct               TX         Revenue Requirement, class cost of service study,         11/26/2008
          TEXAS ENERGY FUTURE HOLDINGS LTD                                                                                                                  class revenue allocation and rate design
 80802    TAMPA ELECTRIC COMPANY                    The Florida Industrial Power Users Group and      080317-EI             Direct                FL        Revenue Requirements, retail class cost of service        11/26/2008
                                                    Mosaic Company                                                                                          study, class revenue allocation, firm and non firm rate
                                                                                                                                                            design and the Transmission Base Rate Adjustment

 80601    SOUTHWESTERN PUBLIC SERVICE COMPANY       Texas Industrial Energy Consumers                  35763          Supplemental Direct        TX         Recovery of Energy Efficiency Costs                       11/6/2008

 80601    SOUTHWESTERN PUBLIC SERVICE COMPANY       Texas Industrial Energy Consumers                  35763            Cross-Rebuttal           TX         Cost Allocation, Demand Ratchet, Renewable Energy         10/28/2008
                                                                                                                                                            Certificates (REC)
 80601    SOUTHWESTERN PUBLIC SERVICE COMPANY       Texas Industrial Energy Consumers                  35763                Direct               TX         Revenue Requirements, Fuel Reconciliation Revenue         10/13/2008
                                                                                                                                                            Allocation, Cost-of-Service and Rate Design Issues
 50106    ALABAMA POWER COMPANY                     Alabama Industrial Energy Consumers                18148                Direct                AL        Energy Cost Recovery Rate (WITHDRAWN)                     9/16/2008

 50701    ENTERGY TEXAS, INC.                       Texas Industrial Energy Consumers                  35269                Direct               TX         Allocation of rough production costs equalization          7/9/2008
                                                                                                                                                            payments
 70703    ENTERGY GULF STATES UTILITIES, TEXAS      Texas Industrial Energy Consumers                  34800                Direct               TX         Non-Unanimous Stipulation                                 6/11/2008

 50103    TEXAS PUC STAFF                           Texas Industrial Energy Consumers                  33672         Supplemental Rebuttal       TX         Transmission Optimization and Ancillary Services           6/3/2008
                                                                                                                                                            Studies
 50103    TEXAS PUC STAFF                           Texas Industrial Energy Consumers                  33672          Supplemental Direct        TX         Transmission Optimization and Ancillary Services          5/23/2008
                                                                                                                                                            Studies
 60104    SOUTHWESTERN ELECTRIC POWER COMPANY       Texas Industrial Energy Consumers                  33891          Supplemental Direct        TX         Certificate of Convenience and Necessity                   5/8/2008
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                                                                                                                                                                                                   m~ÖÉ=VP

                                                                     Testimony Filed in Regulatory Proceedings
                                                                                 by Jeffry Pollock


                                                                                                                                    REGULATORY
PROJECT                      UTILITY                               ON BEHALF OF                      DOCKET            TYPE         JURISDICTION                          SUBJECT                           DATE
 70703    ENTERGY GULF STATES UTILITES, TEXAS        Texas Industrial Energy Consumers                34800        Cross-Rebuttal       TX         Cost Allocation and Rate Design and Competitive        4/18/2008
                                                                                                                                                   Generation Service
 70703    ENTERGY GULF STATES UTILITES, TEXAS        Texas Industrial Energy Consumers                34800            Direct           TX         Eligible Fuel Expense                                  4/11/2008

 70703    ENTERGY GULF STATES UTILITES, TEXAS        Texas Industrial Energy Consumers                34800            Direct           TX         Competitive Generation Service Tariff                  4/11/2008

 70703    ENTERGY GULF STATES UTILITES, TEXAS        Texas Industrial Energy Consumers                34800            Direct           TX         Revenue Requirements                                   4/11/2008

 70703    ENTERGY GULF STATES UTILITES, TEXAS        Texas Industrial Energy Consumers                34800            Direct           TX         Cost of Service study, revenue allocation, design of   4/11/2008
                                                                                                                                                   firm, interruptible and standby service tariffs;
                                                                                                                                                   interconnection costs

 41229    TEXAS-NEW MEXICO POWER COMPANY             Texas Industrial Energy Consumers                35038           Rebuttal          TX         Over $5 Billion Compliance Filing                      4/14/2008

 60303    GEORGIA POWER COMPANY                      Georgia Industrial Group/Georgia Traditional     26794            Direct           GA         Fuel Cost Recovery                                     4/15/2008
                                                     Manufacturers Group
 71202    SOUTHWESTERN PUBLIC SERVICE COMPANY        Occidental Periman Ltd.                        07-00319-UT       Rebuttal          NM         Revenue requirements, cost of service study, rate      3/28/2008
                                                                                                                                                   design
 61101    AEP TEXAS CENTRAL COMPANY                  Texas Industrial Energy Consumers                35105            Direct           TX         Over $5 Billion Compliance Filing                      3/20/2008

 51101    CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC   Texas Industrial Energy Consumers                32902            Direct           TX         Over $5 Billion Compliance Filing                      3/20/2008

 71202    SOUTHWESTERN PUBLIC SERVICE COMPANY        Occidental Periman Ltd.                        07-00319-UT        Direct           NM         Revenue requirements, cost of service study (COS);      3/7/2008
                                                                                                                                                   rate design
 50701    ENTERGY GULF STATES UTILITIES TEXAS        Texas Industrial Energy Consumers                34724            Direct           TX         IPCR Rider increase and interim surcharge              11/28/2007

 70601    GEORGIA POWER COMPANY                      Georgia Industrial Group/Georgia Traditional    25060-U           Direct           GA         Return on equity; cost of service study; revenue       10/24/2007
                                                     Manufacturers Group                                                                           allocation; ILR Rider; spinning reserve tariff; RTP

 70303    ONCOR ELECTRIC DELIVERY COMPANY &          Texas Industrial Energy Consumers                34077            Direct           TX         Acquisition; public interest                           9/14/2007
          TEXAS ENERGY FUTURE HOLDINGS LTD
 60104    SOUTHWESTERN ELECTRIC POWER COMPANY        Texas Industrial Energy Consumers                33891            Direct           TX         Certificate of Convenience and Necessity               8/30/2007

 61201    ALTAMAHA ELECTRIC MEMBERSHIP CORPORATION   SP Newsprint Company                            25226-U          Rebuttal          GA         Discriminatory Pricing; Service Territorial Transfer   7/17/2007

 61201    ALTAMAHA ELECTRIC MEMBERSHIP CORPORATION   SP Newsprint Company                            25226-U           Direct           GA         Discriminatory Pricing; Service Territorial Transfer    7/6/2007

 70502    PROGRESS ENERGY FLORIDA                    Florida Industrial Power Users Group            070052-EI         Direct            FL        Nuclear uprate cost recovery                           6/19/2007

 70603    ELECTRIC TRANSMISSION TEXAS LLC            Texas Industrial Energy Consumers                33734            Direct           TX         Certificate of Convenience and Necessity                6/8/2007

 60601    TEXAS PUC STAFF                            Texas Industrial Energy Consumers                32795       Rebuttal Remand       TX         Interest rate on stranded cost reconciliation          6/15/2007

 60601    TEXAS PUC STAFF                            Texas Industrial Energy Consumers                32795           Remand            TX         Interest rate on stranded cost reconciliation           6/8/2007

 50103    TEXAS PUC STAFF                            Texas Industrial Energy Consumers                33672           Rebuttal          TX         CREZ Nominations                                       5/21/2007

 50701    ENTERGY GULF STATES UTILITES, TEXAS        Texas Industrial Energy Consumers                33687            Direct           TX         Transition to Competition                              4/27/2007
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                                                                    Testimony Filed in Regulatory Proceedings
                                                                                by Jeffry Pollock


                                                                                                                          REGULATORY
PROJECT                      UTILITY                              ON BEHALF OF                 DOCKET        TYPE         JURISDICTION                         SUBJECT                          DATE
 50103    TEXAS PUC STAFF                           Texas Industrial Energy Consumers           33672        Direct           TX         CREZ Nominations                                      4/24/2007

 61101    AEP TEXAS CENTRAL COMPANY                 Texas Industrial Energy Consumers           33309    Cross-Rebuttal       TX         Cost Allocation,Rate Design, Riders                   4/3/2007

 50701    ENTERGY GULF STATES UTILITIES TEXAS       Texas Industrial Energy Consumers           32710    Cross-Rebuttal       TX         Fuel and Rider IPCR Reconcilation                     3/16/2007

 61101    AEP TEXAS NORTH COMPANY                   Texas Industrial Energy Consumers           33310        Direct           TX         Cost Allocation,Rate Design, Riders                   3/13/2007

 61101    AEP TEXAS CENTRAL COMPANY                 Texas Industrial Energy Consumers           33309        Direct           TX         Cost Allocation,Rate Design, Riders                   3/13/2007

 50701    ENTERGY GULF STATES UTILITIES TEXAS       Texas Industrial Energy Consumers           32710        Direct           TX         Fuel and Rider IPCR Reconcilation                     2/28/2007

 41219    AEP TEXAS NORTH COMPANY                   Texas Industrial Energy Consumers           31461        Direct           TX         Rider CTC design                                      2/15/2007

 50701    ENTERGY GULF STATES UTILITIES TEXAS       Texas Industrial Energy Consumers           33586    Cross-Rebuttal       TX         Hurricane Rita reconstruction costs                   1/30/2007

 60104    SOUTHWESTERN ELECTRIC POWER COMPANY       Texas Industrial Energy Consumers           32898        Direct           TX         Fuel Reconciliation                                   1/29/2007


 50701    ENTERGY GULF STATES UTILITIES TEXAS       Texas Industrial Energy Consumers           33586        Direct           TX         Hurricane Rita reconstruction costs                   1/18/2007

 60303    GEORGIA POWER COMPANY                     Georgia Industrial Group/Georgia Textile   23540-U       Direct           GA         Fuel Cost Recovery                                    1/11/2007
                                                    Manufacturers Group
 60503    SOUTHWESTERN PUBLIC SERVICE COMPANY       Texas Industrial Energy Consumers           32766    Cross Rebuttal       TX         Cost allocation, Cost of service, Rate design         1/8/2007

 60503    SOUTHWESTERN PUBLIC SERVICE COMPANY       Texas Industrial Energy Consumers           32766        Direct           TX         Cost allocation, Cost of service, Rate design        12/22/2006

 60503    SOUTHWESTERN PUBLIC SERVICE COMPANY       Texas Industrial Energy Consumers           32766        Direct           TX         Revenue Requirements,                                12/15/2006

 60503    SOUTHWESTERN PUBLIC SERVICE COMPANY       Texas Industrial Energy Consumers           32766        Direct           TX         Fuel Reconcilation                                   12/15/2006

 50701    ENTERGY GULF STATES UTILITIES TEXAS       Texas Industrial Energy Consumers           32907    Cross Rebuttal        TX        Hurricane Rita reconstruction costs                   10/12/06

 50701    ENTERGY GULF STATES UTILITIES TEXAS       Texas Industrial Energy Consumers           32907        Direct            TX        Hurricane Rita reconstruction costs                   10/09/06

 60601    TEXAS PUC STAFF                           Texas Industrial Energy Consumers           32795    Cross Rebuttal       TX         Stranded Cost Reallocation                            09/07/06

 60101    COLQUITT EMC                              ERCO Worldwide                             23549-U       Direct           GA         Service Territory Transfer                            08/10/06

 60601    TEXAS PUC STAFF                           Texas Industrial Energy Consumers           32795        Direct           TX         Stranded Cost Reallocation                            08/23/06

 60104    SOUTHWESTERN ELECTRIC POWER COMPANY       Texas Industrial Energy Consumers           32672        Direct           TX         ME-SPP Transfer of Certificate to SWEPCO              8/23/2006

 50503    AEP TEXAS CENTRAL COMPANY                 Texas Industrial Energy Consumers           32758        Direct           TX         Rider CTC design and cost recovery                    08/24/06

 60503    SOUTHWESTERN PUBLIC SERVICE COMPANY       Texas Industrial Energy Consumers           32685        Direct           TX         Fuel Surcharge                                        07/26/06

 60301    PUBLIC SERVICE ELECTRIC AND GAS COMPANY   New Jersey Large Energy Consumers          171406        Direct           NJ         Gas Delivery Cost allocation and Rate design          06/21/06

 60303    GEORGIA POWER COMPANY                     Georgia Industrial Group/Georgia Textile   22403-U       Direct           GA         Fuel Cost Recovery Allowance                          05/05/06
                                                    Manufacturers Group
                                                                                                                                                                                                   gÉÑÑêó=mçääçÅâ
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                                                                                                                                                                                                   m~ÖÉ=VR

                                                                     Testimony Filed in Regulatory Proceedings
                                                                                 by Jeffry Pollock


                                                                                                                                        REGULATORY
PROJECT                      UTILITY                               ON BEHALF OF                    DOCKET               TYPE            JURISDICTION                         SUBJECT                         DATE
 50503    AEP TEXAS CENTRAL COMPANY                  Texas Industrial Energy Consumers               32475          Cross-Rebuttal          TX         ADFIT Benefit                                        04/27/06

 50503    AEP TEXAS CENTRAL COMPANY                  Texas Industrial Energy Consumers               32475              Direct              TX         ADFIT Benefit                                        04/17/06

 41229    TEXAS-NEW MEXICO POWER COMPANY             Texas Industrial Energy Consumers               31994          Cross-Rebuttal          TX         Stranded Costs and Other True-Up Balances           3/16/2006

 41229    TEXAS-NEW MEXICO POWER COMPANY             Texas Industrial Energy Consumers               31994              Direct              TX         Stranded Costs and Other True-Up Balances           3/10/2006

 50303    SOUTHWESTERN PUBLIC SERVICE COMPANY        Occidental Periman Ltd.                                            Direct              NM         Fuel Reconciliation                                  3/6/2006
                                                     Occidental Power Marketing                  ER05-168-001
 50701    ENTERGY GULF STATES UTILITIES TEXAS        Texas Industrial Energy Consumers                              Cross-Rebuttal           TX        Transition to Competition Costs                      01/13/06
                                                                                                     31544
 50701    ENTERGY GULF STATES UTILITIES TEXAS        Texas Industrial Energy Consumers                                  Direct               TX        Transition to Competition Costs                      01/13/06
                                                                                                     31544
 50601    PUBLIC SERVICE ELECTRIC AND GAS COMPANY    New Jersey Large Energy Consumers          BPU EM05020106        Surrebuttal            NJ        Merger                                              12/22/2005
          AND EXELON CORPORATION                     Retail Energy Supply Association           OAL PUC-1874-05
 50705    SOUTHWESTERN PUBLIC SERVICE COMPANY        Occidental Periman Ltd.                     EL05-19-002;        Responsive            FERC        Fuel Cost adjustment clause (FCAC)                  11/18/2005
                                                     Occidental Power Marketing                  ER05-168-001
 50601    PUBLIC SERVICE ELECTRIC AND GAS COMPANY    New Jersey Large Energy Consumers          BPU EM05020106          Direct               NJ        Merger                                              11/14/2005
          AND EXELON CORPORATION                     Retail Energy Supply Association           OAL PUC-1874-05
 50102    PUBLIC UTILITY COMMISSION OF TEXAS         Texas Industrial Energy Consumers               31540              Direct               TX        Nodal Market Protocols                              11/10/2005

 50701    ENTERGY GULF STATES UTILITIES TEXAS        Texas Industrial Energy Consumers               31315          Cross-Rebuttal           TX        Recovery of Purchased Power Capacity Costs          10/4/2005

 50701    ENTERGY GULF STATES UTILITIES TEXAS        Texas Industrial Energy Consumers               31315              Direct               TX        Recovery of Purchased Power Capacity Costs          9/22/2005

 50705    SOUTHWESTERN PUBLIC SERVICE COMPANY        Occidental Periman Ltd.                     EL05-19-002;        Responsive            FERC        Fuel Cost Adjustment Clause (FCAC)                  9/19/2005
                                                     Occidental Power Marketing                  ER05-168-001
 50503    AEP TEXAS CENTRAL COMPANY                  Texas Industrial Energy Consumers               31056              Direct               TX        Stranded Costs and Other True-Up Balances            9/2/2005

 50705    SOUTHWESTERN PUBLIC SERVICE COMPANY        Occidental Periman Ltd.                      EL05-19-00;           Direct             FERC        Fuel Cost adjustment clause (FCAC)                  8/19/2006
                                                     Occidental Power Marketing                   ER05-168-00
 50203    GEORGIA POWER COMPANY                      Georgia Industrial Group/Georgia Textile       19142-U             Direct              GA         Fuel Cost Recovery                                   4/8/2005
                                                     Manufacturers Group
 41230    CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC   Texas Industrial Energy Consumers               30706              Direct               TX        Competition Transition Charge                       3/16/2005

 41230    CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC   Texas Industrial Energy Consumers               30485        Supplemental Direct        TX        Financing Order                                     1/14/2005

 41230    CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC   Texas Industrial Energy Consumers               30485              Direct               TX        Financing Order                                      1/7/2005

 8201     PUBLIC SERVICE COMPANY OF COLORADO         Colorado Energy Consumers                     04S-164E         Cross Answer            CO         Cost of Service Study, Interruptible Rate Design    12/13/2004

 8201     PUBLIC SERVICE COMPANY OF COLORADO         Colorado Energy Consumers                     04S-164E             Answer              CO         Cost of Service Study, Interruptible Rate Design    10/12/2004

 8244     GEORGIA POWER COMPANY                      Georgia Industrial Group/Georgia Textile       18300-U             Direct              GA         Revenue Requirements, Revenue Allocation, Cost of   10/8/2004
                                                     Manufacturers Group                                                                               Service, Rate Design, Economic Development
 8195     CENTERPOINT, RELIANT AND TEXAS GENCO       Texas Industrial Energy Consumers               29526              Direct              TX         True-Up                                              6/1/2004
                                                                                                                                                                                                     gÉÑÑêó=mçääçÅâ
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                                                                                                                                                                                                     m~ÖÉ=VS

                                                                     Testimony Filed in Regulatory Proceedings
                                                                                 by Jeffry Pollock


                                                                                                                                         REGULATORY
PROJECT                      UTILITY                               ON BEHALF OF                    DOCKET                TYPE            JURISDICTION                         SUBJECT                         DATE
 8156     GEORGIA POWER COMPANY/SAVANNAH ELECTRIC   Georgia Industrial Group                    17687-U/17688-U          Direct              GA         Demand Side Management                              5/14/2004
          AND POWER COMPANY
 8148     TEXAS-NEW MEXICO POWER COMPANY            Texas Industrial Energy Consumers                29206               Direct              TX         True-Up                                             3/29/2004

 8095     CONECTIV POWER DELIVERY                   New Jersey Large Energy Consumers             ER03020110           Surrebuttal           NJ         Cost of Service                                     3/18/2004

 8111     AEP TEXAS CENTRAL COMPANY                 Texas Industrial Energy Consumers                28840              Rebuttal             TX         Cost Allocation and Rate Design                      2/4/2004

 8095     CONECTIV POWER DELIVERY                   New Jersey Large Energy Consumers             ER03020110             Direct              NJ         Cost Allocation and Rate Design                      1/4/2004

 7850     RELIANT ENERGY HL&P                       Texas Industrial Energy Consumers                26195         Supplemental Direct       TX         Fuel Reconciliation                                 9/23/2003

 8045     VIRGINIA ELECTRIC AND POWER COMPANY       Virginia Committee for Fair Utility Rates   PUE-2003-00285           Direct              VA         Stranded Cost                                        9/5/2003

 8022     GEORGIA POWER COMPANY                     Georgia Industrial Group/Georgia Textile        17066-U              Direct              GA         Fuel Cost Recovery                                  7/22/2003
                                                    Manufacturers Group
 8002     AEP TEXAS CENTRAL COMPANY                 Flint Hills Resources, LP                        25395               Direct              TX         Delivery Service Tariff Issues                       5/9/2003

 7857     PUBLIC SERVICE ELECTRIC AND GAS COMPANY   New Jersey Large Energy Consumers             ER02050303          Supplemental           NJ         Cost of Service                                     3/14/2003

 7850     RELIANT ENERGY HL&P                       Texas Industrial Energy Consumers                26195               Direct              TX         Fuel Reconciliation                                 12/31/2002

 7857     PUBLIC SERVICE ELECTRIC AND GAS COMPANY   New Jersey Large Energy Consumers             ER02050303           Surrebuttal           NJ         Revenue Allocation                                  12/16/2002

 7836     PUBLIC SERVICE COMPANY OF COLORADO        Colorado Energy Consumers                     02S-315EG              Answer              CO         Incentive Cost Adjustment                           11/22/2002

 7857     PUBLIC SERVICE ELECTRIC AND GAS COMPANY   New Jersey Large Energy Consumers             ER02050303             Direct              NJ         Revenue Allocation                                  10/22/2002

 7863     DOMINION VIRGINIA POWER                   Virginia Committee for Fair Utility Rates   PUE-2001-00306           Direct              VA         Generation Market Prices                            8/12/2002

 7718     FLORIDA POWER CORPORATION                 Florida Industrial Power Users Group           000824-EI             Direct               FL        Rate Design                                         1/18/2002

 7633     GEORGIA POWER COMPANY                     Georgia Industrial Group/Georgia Textile        14000-U              Direct              GA         Cost of Service Study, Revenue Allocation,          10/12/2001
                                                    Manufacturers Group                                                                                 Rate Design
 7555     TAMPA ELECTRIC COMPANY                    Florida Industrial Power Users Group           010001-EI             Direct               FL        Rate Design                                         10/12/2001

 7658     SOUTHWESTERN ELECTRIC POWER COMPANY       Texas Industrial Energy Consumers                24468               Direct              TX         Delay of Retail Competition                         9/24/2001

 7647     ENTERGY GULF STATES, INC.                 Texas Industrial Energy Consumers                24469               Direct              TX         Delay of Retail Competition                         9/22/2001

 7608     RELIANT ENERGY HL&P                       Texas Industrial Energy Consumers                23950               Direct              TX         Price to Beat                                        7/3/2001

 7593     GEORGIA POWER COMPANY                     Georgia Industrial Group/Georgia Textile        13711-U              Direct              GA         Fuel Cost Recovery                                  5/11/2001
                                                    Manufacturers Group
 7520     GEORGIA POWER COMPANY                     Georgia Industrial Group/Georgia Textile    12499-U,13305-U,         Direct              GA         Integrated Resource Planning                        5/11/2001
          SAVANNAH ELECTRIC & POWER COMPANY         Manufacturers Group                             13306-U
 7303     ENTERGY GULF STATES, INC.                 Texas Industrial Energy Consumers                22356              Rebuttal             TX         Allocation/Collection of Municipal Franchise Fees   3/31/2001
                                                                                                                                                                                                 gÉÑÑêó=mçääçÅâ
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                                                                                                                                                                                                 m~ÖÉ=VT

                                                                Testimony Filed in Regulatory Proceedings
                                                                            by Jeffry Pollock


                                                                                                                                       REGULATORY
PROJECT                       UTILITY                         ON BEHALF OF                      DOCKET                 TYPE            JURISDICTION                         SUBJECT                         DATE
 7309     SOUTHWESTERN PUBLIC SERVICE COMPANY   Texas Industrial Energy Consumers                22351             Cross-Rebuttal          TX         Energy Efficiency Costs                             2/22/2001

 7305     CPL, SWEPCO, and WTU                  Texas Industrial Energy Consumers          22352, 22353, 22354     Cross-Rebuttal          TX         Allocation/Collection of Municipal Franchise Fees   2/20/2001

 7423     GEORGIA POWER COMPANY                 Georgia Industrial Group/Georgia Textile        13140-U                Direct              GA         Interruptible Rate Design                           2/16/2001
                                                Manufacturers Group
 7305     CPL, SWEPCO, and WTU                  Texas Industrial Energy Consumers          22352, 22353, 22354   Supplemental Direct       TX         Transmission Cost Recovery Factor                   2/13/2001

 7310     TEXAS-NEW MEXICO POWER COMPANY        Texas Industrial Energy Consumers                22349             Cross-Rebuttal          TX         Rate Design                                         2/12/2001

 7308     TXU ELECTRIC COMPANY                  Texas Industrial Energy Consumers                22350             Cross-Rebuttal          TX         Unbundled Cost of Service                           2/12/2001

 7303     ENTERGY GULF STATES, INC.             Texas Industrial Energy Consumers                22356             Cross-Rebuttal          TX         Stranded Cost Allocation                             2/6/2001

 7308     TXU ELECTRIC COMPANY                  Texas Industrial Energy Consumers                22350                 Direct              TX         Rate Design                                          2/5/2001

 7303     ENTERGY GULF STATES, INC.             Texas Industrial Energy Consumers                22356           Supplemental Direct       TX         Rate Design                                         1/25/2001

 7307     RELIANT ENERGY HL&P                   Texas Industrial Energy Consumers                22355             Cross-Rebuttal          TX         Stranded Cost Allocation                            1/12/2001

 7303     ENTERGY GULF STATES, INC.             Texas Industrial Energy Consumers                22356                 Direct              TX         Stranded Cost Allocation                             1/9/2001

 7307     RELIANT ENERGY HL&P                   Texas Industrial Energy Consumers                22355                 Direct              TX         Cost Allocation                                     12/13/2000

 7375     CENTRAL POWER AND LIGHT COMPANY       Texas Industrial Energy Consumers                22352             Cross-Rebuttal          TX         CTC Rate Design                                     12/1/2000

 7375     CENTRAL POWER AND LIGHT COMPANY       Texas Industrial Energy Consumers                22352                 Direct              TX         Cost Allocation                                     11/1/2000

 7308     TXU ELECTRIC COMPANY                  Texas Industrial Energy Consumers                22350                 Direct              TX         Cost Allocation                                     11/1/2000

 7308     TXU ELECTRIC COMPANY                  Texas Industrial Energy Consumers                22350             Cross-Rebuttal          TX         Cost Allocation                                     11/1/2000

 7305     CPL, SWEPCO, and WTU                  Texas Industrial Energy Consumers          22352, 22353, 22354         Direct              TX         Excess Cost Over Market                             11/1/2000

 7315     VARIOUS UTILITIES                     Texas Industrial Energy Consumers                22344                 Direct              TX         Generic Customer Classes                            10/14/2000

 7308     TXU ELECTRIC COMPANY                  Texas Industrial Energy Consumers                22350                 Direct              TX         Excess Cost Over Market                             10/10/2000

 7315     VARIOUS UTILITIES                     Texas Industrial Energy Consumers                22344                Rebuttal             TX         Excess Cost Over Market                             10/1/2000

 7310     TEXAS-NEW MEXICO POWER COMPANY        Texas Industrial Energy Consumers                22349             Cross-Rebuttal          TX         Generic Customer Classes                            10/1/2000

 7310     TEXAS-NEW MEXICO POWER COMPANY        Texas Industrial Energy Consumers                22349                 Direct              TX         Excess Cost Over Market                             9/27/2000

 7307     RELIANT ENERGY HL&P                   Texas Industrial Energy Consumers                22355             Cross-Rebuttal          TX         Excess Cost Over Market                             9/26/2000

 7307     RELIANT ENERGY HL&P                   Texas Industrial Energy Consumers                22355                 Direct              TX         Excess Cost Over Market                             9/19/2000

 7334     GEORGIA POWER COMPANY                 Georgia Industrial Group/Georgia Textile        11708-U               Rebuttal             GA         RTP Petition                                        3/24/2000
                                                Manufacturers Group
                                                                                                                                                                                                 gÉÑÑêó=mçääçÅâ
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                                                                                                                                                                                                 m~ÖÉ=VU
                                                                 Testimony Filed in Regulatory Proceedings
                                                                             by Jeffry Pollock


                                                                                                                                       REGULATORY
PROJECT                        UTILITY                         ON BEHALF OF                           DOCKET              TYPE         JURISDICTION                          SUBJECT                     DATE
 7334     GEORGIA POWER COMPANY                 Georgia Industrial Group/Georgia Textile              11708-U             Direct           GA         RTP Petition                                      3/1/2000
                                                Manufacturers Group
 7232     PUBLIC SERVICE COMPANY OF COLORADO    Colorado Industrial Energy Consumers                 99A-377EG           Answer            CO         Merger                                           12/1/1999

 7258     TXU ELECTRIC COMPANY                  Texas Industrial Energy Consumers                      21527              Direct           TX         Securitization                                   11/24/1999

 7246     CENTRAL POWER AND LIGHT COMPANY       Texas Industrial Energy Consumers                      21528              Direct           TX         Securitization                                   11/24/1999

 7089     VIRGINIA ELECTRIC AND POWER COMPANY   Virginia Committee for Fair Utility Rates            PUE980813            Direct           VA         Unbundled Rates                                   7/1/1999

 7090     AMERICAN ELECTRIC POWER SERVICE       Old Dominion Committee for Fair Utility Rates        PUE980814            Direct           VA         Unbundled Rates                                  5/21/1999
          CORPORATION
 7142     SHARYLAND UTILITIES, L.P.             Sharyland Utilities                                    20292             Rebuttal          TX         Certificate of Convenience and Necessity         4/30/1999

 7060     PUBLIC SERVICE COMPANY OF COLORADO    Colorado Industrial Energy Consumers Group            98A-511E            Direct           CO         Allocation of Pollution Control Costs             3/1/1999


 7039     SAVANNAH ELECTRIC AND POWER COMPANY   Various Industrial Customers                          10205-U             Direct           GA         Fuel Costs                                        1/1/1999

 6945     TAMPA ELECTRIC COMPANY                Florida Industrial Power Users Group                 950379-EI            Direct            FL        Revenue Requirement                              10/1/1998

 6873     GEORGIA POWER COMPANY                 Georgia Industrial Group                               9355-U             Direct           GA         Revenue Requirement                              10/1/1998

 6729     VIRGINIA ELECTRIC AND POWER COMPANY   Virginia Committee for Fair Utility Rates       PUE960036,PUE960296       Direct           VA         Alternative Regulatory Plan                       8/1/1998

 6713     CENTRAL POWER AND LIGHT COMPANY       Texas Industrial Energy Consumers                      16995          Cross-Rebuttal       TX         IRR                                               1/1/1998

 6582     HOUSTON LIGHTING & POWER COMPANY      Lyondell Petrochemical Company                        96-02867            Direct          COURT       Interruptible Power                                1997

 6758     SOUTHWESTERN ELECTRIC POWER COMPANY   Texas Industrial Energy Consumers                      17460              Direct           TX         Fuel Reconciliation                              12/1/1997

 6729     VIRGINIA ELECTRIC AND POWER COMPANY   Virginia Committee for Fair Utility Rates       PUE960036,PUE960296       Direct           VA         Alternative Regulatory Plan                      12/1/1997

 6713     CENTRAL POWER AND LIGHT COMPANY       Texas Industrial Energy Consumers                      16995              Direct           TX         Rate Design                                      12/1/1997

 6646     ENTERGY TEXAS                         Texas Industrial Energy Consumers                      16705             Rebuttal          TX         Competitive Issues                               10/1/1997

 6646     ENTERGY TEXAS                         Texas Industrial Energy Consumers                      16705             Rebuttal          TX         Competition                                      10/1/1997

 6646     ENTERGY TEXAS                         Texas Industrial Energy Consumers                 XXX-XX-XXXX/16705       Direct           TX         Rate Design                                       9/1/1997

 6646     ENTERGY TEXAS                         Texas Industrial Energy Consumers                      16705              Direct           TX         Wholesale Sales                                   8/1/1997

 6744     TAMPA ELECTRIC COMPANY                Florida Industrial Power Users Group                 970171-EU            Direct            FL        Interruptible Rate Design                         5/1/1997

 6632     MISSISSIPPI POWER COMPANY             Colonial Pipeline Company                            96-UN-390            Direct           MS         Interruptible Rates                               2/1/1997

 6558     TEXAS-NEW MEXICO POWER COMPANY        Texas Industrial Energy Consumers                      15560              Direct           TX         Competition                                      11/11/1996

 6508     TEXAS UTILITIES ELECTRIC COMPANY      Texas Industrial Energy Consumers                      15195              Direct           TX         Treatment of margins                              9/1/1996
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                                                                                                                                                                    m~ÖÉ=VV

                                                                   Testimony Filed in Regulatory Proceedings
                                                                               by Jeffry Pollock


                                                                                                                    REGULATORY
PROJECT                      UTILITY                              ON BEHALF OF          DOCKET          TYPE        JURISDICTION                         SUBJECT           DATE
 6475     TEXAS UTILITIES ELECTRIC COMPANY         Texas Industrial Energy Consumers     15015         DIRECT           TX         Real Time Pricing Rates                8/8/1996

 6449     CENTRAL POWER AND LIGHT COMPANY          Texas Industrial Energy Consumers     14965          Direct          TX         Quantification                         7/1/1996

 6449     CENTRAL POWER AND LIGHT COMPANY          Texas Industrial Energy Consumers     14965          Direct          TX         Interruptible Rates                    5/1/1996

 6449     CENTRAL POWER AND LIGHT COMPANY          Texas Industrial Energy Consumers     14965         Rebuttal         TX         Interruptible Rates                    5/1/1996

 6523     PUBLIC SERVICE COMPANY OF COLORADO       Multiple Intervenors                95A-531EG       Answer           CO         Merger                                 4/1/1996

 6235     TEXAS UTILITIES ELECTRIC COMPANY         Texas Industrial Energy Consumers     13575          Direct          TX         Competitive Issues                     4/1/1996

 6435     SOUTHWESTERN PUBLIC SERVICE COMMISSION   Texas Industrial Energy Consumers     14499          Direct          TX         Acquisition                            11/1/1995

 6391     HOUSTON LIGHTING & POWER COMPANY         Grace, W.R. & Company                 13988         Rebuttal         TX         Rate Design                            8/1/1995

 6353     SOUTHWESTERN PUBLIC SERVICE COMPANY      Texas Industrial Energy Consumers     14174          Direct          TX         Costing of Off-System Sales            8/1/1995

 6157     WEST TEXAS UTILITIES COMPANY             Texas Industrial Energy Consumers     13369         Rebuttal         TX         Cancellation Term                      8/1/1995

 6391     HOUSTON LIGHTING & POWER COMPANY         Grace, W.R. & Company                 13988          Direct          TX         Rate Design                            7/1/1995

 6157     WEST TEXAS UTILITIES COMPANY             Texas Industrial Energy Consumers     13369          Direct          TX         Cancellation Term                      7/1/1995

 6296     GEORGIA POWER COMPANY                    Georgia Industrial Group              5601-U        Rebuttal         GA         EPACT Rate-Making Standards            5/1/1995

 6296     GEORGIA POWER COMPANY                    Georgia Industrial Group              5601-U         Direct          GA         EPACT Rate-Making Standards            5/1/1995

 6278     COMMONWEALTH OF VIRGINIA                 VCFUR/ODCFUR                        PUE940067       Rebuttal         VA         Integrated Resource Planning           5/1/1995

 6295     GEORGIA POWER COMPANY                    Georgia Industrial Group              5600-U      Supplemental       GA         Cost of Service                        4/1/1995

 6063     PUBLIC SERVICE COMPANY OF COLORADO       Multiple Intervenors                94I-430EG       Rebuttal         CO         Cost of Service                        4/1/1995

 6063     PUBLIC SERVICE COMPANY OF COLORADO       Multiple Intervenors                94I-430EG        Reply           CO         DSM Rider                              4/1/1995

 6295     GEORGIA POWER COMPANY                    Georgia Industrial Group              5600-U         Direct          GA         Interruptible Rate Design              3/1/1995

 6278     COMMONWEALTH OF VIRGINIA                 VCFUR/ODCFUR                        PUE940067        Direct          VA         EPACT Rate-Making Standards            3/1/1995

 6125     SOUTHWESTERN PUBLIC SERVICE COMPANY      Texas Industrial Energy Consumers     13456          Direct          TX         DSM Rider                              3/1/1995

 6235     TEXAS UTILITIES ELECTRIC COMPANY         Texas Industrial Energy Consumers   13575|13749      Direct          TX         Cost of Service                        2/1/1995

 6063     PUBLIC SERVICE COMPANY OF COLORADO       Multiple Intervenors                94I-430EG      Answering         CO         Competition                            2/1/1995

 6061     HOUSTON LIGHTING & POWER COMPANY         Texas Industrial Energy Consumers     12065          Direct          TX         Rate Design                            1/1/1995

 6181     GULF STATES UTILITIES COMPANY            Texas Industrial Energy Consumers     12852          Direct          TX         Competitive Alignment Proposal         11/1/1994

 6061     HOUSTON LIGHTING & POWER COMPANY         Texas Industrial Energy Consumers     12065          Direct          TX         Rate Design                            11/1/1994
                                                                                                                                                                    gÉÑÑêó=mçääçÅâ
                                                                                                                                                                    aáêÉÅí=qÉëíáãçåó
                                                                                                                                                                    m~ÖÉ=NMM

                                                                Testimony Filed in Regulatory Proceedings
                                                                            by Jeffry Pollock


                                                                                                               REGULATORY
PROJECT                      UTILITY                          ON BEHALF OF              DOCKET       TYPE      JURISDICTION                         SUBJECT                DATE
 5929     CENTRAL POWER AND LIGHT COMPANY       Texas Industrial Energy Consumers        12820       Direct        TX         Rate Design                                 10/1/1994

 6107     SOUTHWESTERN ELECTRIC POWER COMPANY   Texas Industrial Energy Consumers        12855       Direct        TX         Fuel Reconciliation                         8/1/1994

 6112     HOUSTON LIGHTING & POWER COMPANY      Texas Industrial Energy Consumers        12957       Direct        TX         Standby Rates                               7/1/1994

 5698     GULF POWER COMPANY                    Misc. Group                            931044-EI     Direct         FL        Standby Rates                               7/1/1994

 5698     GULF POWER COMPANY                    Misc. Group                            931044-EI    Rebuttal        FL        Competition                                 7/1/1994

 6043     EL PASO ELECTRIC COMPANY              Phelps Dodge Corporation                 12700       Direct        TX         Revenue Requirement                         6/1/1994

 6082     GEORGIA PUBLIC SERVICE COMMISSION     Georgia Industrial Group                4822-U       Direct        GA         Avoided Costs                               5/1/1994

 6075     GEORGIA POWER COMPANY                 Georgia Industrial Group                4895-U       Direct        GA         FPC Certification Filing                    4/1/1994

 6025     MISSISSIPPI POWER & LIGHT COMPANY     MIEG                                   93-UA-0301   Comments       MS         Environmental Cost Recovery Clause          1/1/1994

 5971     FLORIDA POWER & LIGHT COMPANY         Florida Industrial Power Users Group   940042-EI     Direct         FL        Section 712 Standards of 1992 EPACT         1/1/1994
                                                                           Jeffry Pollock
                                                                           Direct Testimony
                                                                           Page 101




                                        APPENDIX C

1              Procedures for Conducting a Class Cost-of-Service Study


2    Q   WHAT PROCEDURES ARE USED IN A COST-OF-SERVICE STUDY?

3    A   The basic procedure for conducting a class cost-of-service study is fairly simple.

4        First, we identify the different types of costs (functionalization), determine their

5        primary causative factors (classification), and then apportion each item of cost

6        among the various rate classes (allocation). Adding up the individual pieces

7        gives the total cost for each class.

8               Identifying the utility’s different levels of operation is a process referred to

9        as functionalization. The utility’s investments and expenses are separated into

10       production, transmission, distribution, and other functions. To a large extent, this

11       is done in accordance with the Uniform System of Accounts developed by the

12       Federal Energy Regulatory Commission (FERC).

13              Once costs have been functionalized, the next step is to identify the

14       primary causative factor (or factors). This step is referred to as classification.

15       Costs are classified as demand-related, energy-related or customer-related.

16       Demand (or capacity) related costs vary with peak demand, which is measured in

17       kilowatts (or kW). This includes production, transmission, and some distribution

18       investment and related fixed operation and maintenance (O&M) expenses. As

19       explained later, peak demand determines the amount of capacity needed for

20       reliable service. Energy-related costs vary with the production of energy, which

21       is measured in kilowatt-hours (or kWh). Energy-related costs include fuel and

                                                                                   Appendix C

                                         J.POLLOCK
                                        INCORPORATED
                                                                            Jeffry Pollock
                                                                            Direct Testimony
                                                                            Page 102



1        variable O&M expense. Customer-related costs vary directly with the number of

2        customers and include expenses such as meters, service drops, billing, and

3        customer service.

4                Each functionalized and classified cost must then be allocated to the

5        various customer classes. This is accomplished by developing allocation factors

6        that reflect the percentage of the total cost that should be paid by each class.

7        The allocation factors should reflect cost causation; that is, the degree to which

8        each class caused the utility to incur the cost.


9    Q   WHAT KEY PRINCIPLES ARE RECOGNIZED IN A CLASS COST-OF-

10       SERVICE STUDY?

11   A   A properly conducted class cost-of-service study recognizes two key cost

12       causation principles. First, customers are served at different delivery voltages.

13       This affects the amount of investment the utility must make to deliver electricity to

14       the meter. Second, since cost causation is also related to how electricity is used,

15       both the timing and rate of energy consumption (i.e., demand) are critical.

16       Because electricity cannot be stored for any significant time period, a utility must

17       acquire sufficient generation resources and construct the required transmission

18       facilities to meet the maximum projected demand, including a reserve margin as

19       a contingency against forced and unforced outages, severe weather, and load

20       forecast error. Customers that use electricity during the critical peak hours cause

21       the utility to invest in generation and transmission facilities.




                                                                                  Appendix C

                                         J.POLLOCK
                                         INCORPORATED
                                                                         Jeffry Pollock
                                                                         Direct Testimony
                                                                         Page 103



1    Q   WHAT FACTORS CAUSE THE PER-UNIT COSTS TO DIFFER AMONG

2        CUSTOMER CLASSES?

3    A   Factors that affect the per-unit cost include whether a customer’s usage is

4        constant or fluctuating (load factor), whether the utility must invest in

5        transformers and distribution systems to provide the electricity at lower voltage

6        levels, the amount of electricity that a customer uses, and the quality of service

7        (e.g., firm or non-firm). In general, industrial consumers are less costly to serve

8        on a per unit basis because they:

9               1. Operate at higher load factors;

10              2. Take service at higher delivery voltages; and

11              3. Use more electricity per customer.

12       A customer that purchases non-firm or interruptible service is receiving a lower

13       quality of service than firm service. Thus, non-firm service is less costly per unit

14       than firm service for customers that otherwise have the same characteristics.

15              Finally, a customer that assumes price risk, such as the case under      ulf’s

16       Schedule RTP (Real Time Pricing), is also less costly to serve.            An RTP

17       customer pays the hourly incremental cost plus a contribution to fixed costs. The

18       incremental cost is not known until 24 hours prior to the next day. Thus, RTP is

19       unlike any other rate.

20              All of these factors explain why some customers pay lower average rates

21       than others.

22              For example, the difference in the losses incurred to deliver electricity at

23       the various delivery voltages is a reason why the per-unit energy cost to serve is

                                                                                 Appendix C

                                        J.POLLOCK
                                        INCORPORATED
                                                                     Jeffry Pollock
                                                                     Direct Testimony
                                                                     Page 104



1    not the same for all customers.       More losses occur to deliver electricity at

2    distribution voltage (either primary or secondary) than at transmission voltage,

3    which is generally the level at which industrial customers take service. This

4    means that the cost per kWh is lower for a transmission customer than a

5    distribution customer. The cost to deliver a kWh at primary distribution, though

6    higher than the per-unit cost at transmission, is lower than the delivered cost at

7    secondary distribution.

8           In addition to lower losses, transmission customers do not use the

9    distribution system. Instead, transmission customers construct and own their

10   own distribution systems. Thus, distribution system costs are not allocated to

11   transmission level customers who do not use that system.               Distribution

12   customers, by contrast, require substantial investments in these lower voltage

13   facilities to provide service.    Secondary distribution customers require more

14   investment than do primary distribution customers. This results in a different cost

15   to serve each type of customer.

16          Two other cost drivers are efficiency and size.         These drivers are

17   important because most fixed costs are allocated on either a demand or

18   customer basis.

19          Efficiency can be measured in terms of load factor. Load factor is the

20   ratio of average demand (i.e., energy usage divided by the number of hours in

21   the period) to peak demand. A customer that operates at a high load factor is

22   more efficient than a lower load factor customer because it requires less capacity

23   for the same amount of energy.         For example, assume that two customers

                                                                            Appendix C

                                      J.POLLOCK
                                      INCORPORATED
                                                                Jeffry Pollock
                                                                Direct Testimony
                                                                Page 105



1   purchase the same amount of energy, but one customer has an 80% load factor

2   and the other has a 40% load factor. The 40% load factor customers would have

3   twice the peak demand of the 80% load factor customers, and the utility would

4   therefore require twice as much capacity to serve the 40% load factor customer

5   as the 80% load factor. Said differently, the fixed costs to serve a high load

6   factor customer are spread over more kWh usage than for a low load factor

7   customer.




                                                                       Appendix C

                                J.POLLOCK
                                INCORPORATED
                                                                                      Exhibit JP-1



                                      ENTERGY TEXAS, INC.
                                Derivation of Test Year Adjusted
                                Purchased Power Capacity Costs
                                   Year Ended June 30, 2011



                                                   Amount           Unit Cost
                                       Test Year    (MW-         ($/kW-Month)            Cost
Line              Description            Cost      Months)     Actual     Pro-Forma     ($000)
                                          (1)        (2)        (3)           (4)         (5)

 1     ETI Proposed Expense                                                             $276,242

 2     Test Year Actual Expense                                                          245,433

       Pro-Forma Adjustments (a)
 3     Third Party Purchases             $30,939       5,584    $5.541      $5.381          (891)
 4     Affiliate Purchases               189,032      21,670       8.723     8.656        (1,462)
 5     Reserve Equalization               25,461       8,309       3.064     3.659         4,944
 6        Total                         $245,433      35,563    $6.901      $6.940       248,024
       Adjust Unit Cost
       for Expiration of the
 7     EAI-WBL Contract (b)                                                              (11,132)

 8     Test Year Adjusted                                                                236,893

 9     Adjustment to ETI's Proposal                                                     ($39,350)




(a)    Column 5 = (Column 4 - Column 3) x Column 2.
(b)    Exhibit JP-2.
                                                                        Exhibit JP-2




                       ENTERGY TEXAS, INC.
                Pro-Forma Adjustment to Recognize
              the Expiration of the EAI-WBL Agreement
                      Year Ended June 30, 2011
              (Units and Dollar Amounts in Thousands)



Line                        Description                   Amount
                                                            (1)

 1     Remove EAI-WBL Purchase for 7 Months                 ($13,860)
       Increase Reserve Equalization Purchases:
 2        Additional Purchase (kW-Months)                       746
 3        Pro-Forma Unit Cost ($/kW-Month)                   $3.659
 4           Incremental Reserve Equalization Purchases      $2,729

 5     Adjustment                                           ($11,132)
                                                                                                                                                             Exhibit JP-3

                                                                     ENTERGY TEXAS, INC.
                                                   Schedule MSS-2 Equalization Calculation for May 2011

              Line             Description         Reference         AR              LA              MS             NO            EGSL            ETI
                                                      (1)            (2)             (3)             (4)            (5)            (6)            (7)
               1     Total Investment                 Input      $411,217,204    $515,213,188    $270,079,412    $27,048,703   $331,270,198   $222,210,474
               2     Deferred Taxes                   Input        36,427,497      58,284,456      31,434,045      3,238,453     28,094,818     19,886,865
               3     Depreciation Reserve             Input       159,055,766     175,602,699      92,625,850     14,199,888    161,930,338     57,270,189
               4     Net Transmission Investment      Input      $215,733,941    $281,326,033    $146,019,517     $9,610,362   $141,245,042   $145,053,420
                     Cost of Money
               5     Debt Ratio (DR)                  Input            47.78%          49.71%          48.48%        45.31%          47.89%         48.64%
               6     Bond Cost (i)                    Input             6.14%           6.80%           6.19%         6.08%           5.87%          5.35%
               7     Preferred Ratio (PR)             Input             3.95%           2.27%           3.58%         4.73%           0.36%
               8     Preferred Cost (p)               Input             5.99%           7.58%           5.69%         4.82%           8.71%
               9     Common Ratio (ER)                Input            48.27%          48.02%          47.94%        49.96%          51.75%         51.36%
               10    Common Cost (c)                  Input            11.00%          11.00%          11.00%        11.00%          11.00%         11.00%
                                                   L5xL6+L7xL8
               11    Cost of Money (COM)             +L9xL10            8.48%           8.83%           8.48%          8.48%          8.53%          8.25%
               12    Tax Rate (F)                     Input             3.58%           3.41%           3.39%          3.58%          3.58%          3.04%
                     Operating Expenses
               13    Depreciation Factor (D)         Input             1.487%          2.803%          2.258%        2.823%          1.982%         2.000%
               14    Insurance Expense (I)           Input                             0.439%          0.409%                        0.629%         0.084%
               15    Property Tax (PT)               Input             0.454%          0.912%          1.741%        1.122%          0.851%         0.751%
               16    Franchise Tax (FT)              Input             0.005%                          0.102%        0.149%         -0.001%         0.148%
               17    Operations & Maintenance        Input             3.779%          4.207%          3.517%        4.755%          5.095%         3.433%
               18    Total Operating Expenses      Sum L13-17          5.724%          8.361%          8.026%        8.849%          8.555%         6.416%
               19    Net Investment Ratio            L4÷L1           52.462%         54.604%         54.065%        35.530%        42.637%        65.277%
                                                    L11+L12+
               20    Annual Ownership Cost %        (L18÷L26)         22.971%         27.557%         26.716%        36.963%        32.179%        21.123%
               21    Annual Ownership Cost $         L4xL20       $49,555,755     $77,525,900     $39,009,863     $3,552,252    $45,451,387    $30,639,937
               22    System Average Annual Ownership Cost                        $245,735,094    $938,988,315        26.17%
               23    System Average Monthly Ownership Cost                                                             2.18%
               24    Responsibility Ratio             Input            20.88%          25.97%          13.63%          4.56%         18.87%         16.09%
                                                       L24x
               25    Transmission Responsibility   $938,988,315 $196,060,760     $243,855,265    $127,984,107    $42,817,867   $177,187,095   $151,083,220
               26    Investment Difference           L25-L4      ($19,673,181) ($37,470,767) ($18,035,409)       $33,207,505    $35,942,053     $6,029,800
               27    Payment (Receipt)             L26x2.18%        ($429,043)      ($817,181)      ($393,325)     $724,206       $783,842       $131,501


_________________________________
Source: ETI Response to Cities 1-1.
                                                                                                                                                                bñÜáÄáí=gmJQ



PUCT Docket 39896
Oties 3-3 (g)

Entergy Operating Companies MSS-2 payments/(recelpts) for the years 2006 - 2011
Credits reflect revenue (receipts); Debits reflect expense (payments)

Year                            EAi                EGSI                  ELL                    EGSL             EMI                ENOI          ETI
2006                     $       7,691,868          (2,649,584)           (8,111,212)                        $    (1,971,870)         5,040,797
2007                             2,204,469           5,882,997            (6,856,050)                             (5,962,975)         4,731,559
2008                            (1,415,587)                               (7,837,669)           11,762,725        (5,653,578)         5,804,604   (2,660,494)
2009                            (3,812,177)                               (7,896,585)            9,427,916        (3,532,269)         6,773,517     (960,402)
2010                            (4,909,612)                               (7,424,245)            7,377,010        (3,835,941)         8,233,158      559,630
2011•                           (2,104,269)                               (1,691,230)            1,515,163        (3,400,589)         4,331,993    1,348,932
Grand Total              $      (2,345,309)          3,233,413     $     (39,816,991)           30,082,815   $   (24,357,222) $      34,915,628   (1,712,334)

•2011 includes January - June 2011

Entergy Operating Companies MSS-2 payments/(recelpts) for the test year July 2010 - June 2011
Credits reflect revenue (receipts); Debits reflect expense (payments)

                                EAi                 ELL                 EGSL                    EMI              ENOI               ETI
7/2010 - 6/2011          $      (4,169,001)          (4,738,043)          3,955,371              (5,329,599) $     8,527,476   $     1,753,797




                  39896                                                                                                            Cities 3-3 LR156
                                                                                Exhibit JP-5




                          ENTERGY TEXAS, INC.
                      Comparison of Book Reserve and
                      Theoretical Reserve By Function
                           At December 31, 2010
                             (Amounts in $000)




                                Book          Theoretical       Surplus
 Line        Function          Reserve         Reserve        (Deficiency)
                                  (1)              (2)            (3)


   1     Production              $585,706         $493,168         $92,537

   2     Transmission             247,315           243,665             3,650

   3     Distribution             275,487           374,326        (98,839)

   4     General                  $60,053           $64,196        ($4,144)




Source: Direct Testimony of Dane A. Watson, Appendix A-1.
                                                                                           Exhibit JP-6




                                  ENTERGY TEXAS, INC.
                Comparison of Book Reserve and Theoretical Reserve
                         For the General Plant Accounts
                               At December 31, 2010
                                 (Amounts in $000)




           FERC                                          Book             Theoretical   Surplus
 Line     Account               Description             Reserve            Reserve    (Deficiency)
                                                            (1)               (2)          (3)


   1       390.0      Structures and Improvements           $20,410          $16,821       $3,589
   2       391.1      Office Furniture & Equipment                (923)             471     (1,394)
   3       391.2      Computer Equipment                     (4,440)          10,790      (15,229)
   4       391.3      Data Handling Equipment                 4,053                 698     3,354
   5       392.0      Transportation Equipment                    (449)              2           (451)
   6       393.0      Stores Equipment                            976          2,091        (1,116)
   7       394.0      Tools, Shop & Garage Equipment          2,813            3,469             (656)
   8       395.0      Laboratory Equipment                   (2,345)                128     (2,473)
   9       396.0      Power Operated Equipment                    348               398           (49)
  10       397.1      Communication Equipment                     (597)        2,001        (2,598)
  11       397.2      Microwave and Fiber Optic              40,511           26,894       13,616
  12       398.0      Misc. Equipment                             (304)             433          (736)
  13          Total                                         $60,053          $64,196      ($4,144)




Source: Direct Testimony of Dane A. Watson, Appendix A-1.
CONTAINS HIGHLY SENSITIVE INFORMATION                                                                                                Exhibit JP-7


                                                             ENTERGY TEXAS, INC.
                                                        Incentive Compensation Expense
                                                          For Year Ended June 30, 2011


                                                                                                              Expense Related to
                                                                                                             Achieving Financial
                                                                      Included in Test Year Expense               Objectives
 Line                       Incentive Plan                            ETI          ESI          Total        Percent   Amount          Source
                                                                      (1)            (2)           (3)         (4)        (5)            (6)
        Annual
  1     Management Incentive Plan                                  $1,184,200    $3,564,998     $4,749,198      0.0%            $0   Cities 10-5
  2     Exempt Incentive Plan                                         983,867       874,470      1,858,337      0.0%            0    Cities 10-6
  3     Teamsharing Incentive Plan                                     71,466         81,981      153,447       0.0%            0    Cities 10-7
  4     Teamsharing Selected Bargaining Units Incentive Plan          384,878              0      384,878       0.0%            0    Cities 10-8
  5     Operational Incentive Plan                                     60,272       121,190       181,462       0.0%            0    Cities 10-11
                                        1
  6     Executive Annual Incentive Plan                               185,409     1,298,038      1,483,447               819,062     Cities 10-4
  7     Total Annual Plans                                         $2,870,092    $5,940,677     $8,810,769              $819,062


        Long Term
  8     Equity Ownership Plan                                         193,187     4,368,180      4,561,367   100.0%     4,561,367    Cities 10-9
  9     Long Term Incentive Program                                    16,652       213,004       229,656    100.0%      229,656
  10    Equity Awards Program                                                0        83,460       83,460    100.0%       83,460
                                                                                                                                     Cities 10-10
  11    Restricted Share Awards Program                                      0      346,256       346,256    100.0%      346,256
  12    Restricted Stock Awards Program                                20,994       135,242       156,236    100.0%      156,236
  13    Total Long Term Plans                                       $230,833     $5,146,142     $5,376,975             $5,376,975


  14    Total                                                      $3,100,925 $11,086,819 $14,187,744                  $6,196,037




1) Financial related percent listed applies to ESI incentives only and is from Exhibit KGG-4.
                                                                                Exhibit JP-8




                           ENTERGY TEXAS, INC.
          Year-To-Year Variation in Expenses by FERC Accounts
            in Which MISO Transition Costs are Being Booked
                            (Amounts in $000)




                                                CY 2009      CY 2010
        FERC                                      vs.          vs.       D39896 vs.
Line   Account             Description          CY 2008      CY 2009      D37744
                                                  (1)          (2)          (3)
       500,506,
 1     556,557     Production O&M Expense         $678.0       $748.0      ($1,716.8)
       560,566,
 2       575       Transmission O&M Expense       1,204.0       208.0       4,393.7

 3       920       A&G Salaries                   1,205.0      2,009.0      2,445.2

 4       921       Office Supplies & Expenses      (357.0)      130.0         (188.8)

 5       923       Outside Services Employed       459.0       2,807.0      (3,271.0)

 6       926       Pensions & Benefits            4,484.0      4,219.0      5,524.0

 7       928       Regulatory Commission Exp.     2,186.0      3,823.0      (1,753.1)

 8       930       General Advertising Exp.         (77.0)        19.0         (17.7)

 8     All Other Applicable Accounts              1,465.0     10,968.0     (21,422.1)

 9         Total                                $11,247.0    $24,931.0   ($16,006.6)
                                                                         Exhibit JP-9
                                                                         Page 1 of 6.




                                            ENTERGY TEXAS, INC.
                                          Municipal Franchise Fee Rate
                                                     By City
                                           Year Ended June 30, 2011


                                                          MFF Fee
                                                           Rate
            Line           Municipality                   ($/kWh)
                                                             (1)
             1     AMES                                   $0.002451
             2     ANAHUAC                                $0.002119
             3     ANDERSON                               $0.002438
             4     BEAUMONT                               $0.002152
             5     BEDIAS                                 $0.002438
             6     BEVIL OAKS                             $0.002472
             7     BREMOND                                $0.002458
             8     BRIDGE CITY                            $0.002398
             9     CALDWELL                               $0.001272
            10     CALVERT                                $0.002520
            11     CHESTER                                $0.002400
            12     CHINA                                  $0.002475
            13     CLEVELAND                              $0.002331
            14     COLMESNEIL                             $0.002557
            15     CONROE                                 $0.001756
            16     CORRIGAN                               $0.002381
            17     CUT AND SHOOT                          $0.002386
            18     DAISETTA                               $0.002045
            19     DAYTON                                 $0.002277
            20     DEVERS                                 $0.001283
            21     FRANKLIN                               $0.002466
            22     GROVES                                 $0.000956
            23     GROVETON                               $0.002503
            24     HARDIN                                 $0.002507
            25     HOUSTON                                $0.001622
            26     HUNTSVILLE                             $0.001905
            27     IOLA                                   $0.002438
            28     KOSSE                                  $0.002540
            29     KOUNTZE                                $0.002114
            30     LIBERTY                                $0.001320
            31     LUMBERTON                              $0.002417
            32     MADISONVILLE                           $0.002333
            33     MIDWAY                                 $0.002517
            34     MONTGOMERY                             $0.002190
            35     NAVASOTA                               $0.002275
            36     NEDERLAND                              $0.002369




_________________________________
Source: Response to TIEC 1-33 and 1-34.
                                                                          Exhibit JP-9
                                                                          Page 2 of 6.




                                             ENTERGY TEXAS, INC.
                                           Municipal Franchise Fee Rate
                                                      By City
                                            Year Ended June 30, 2011


                                                           MFF Fee
                                                            Rate
            Line            Municipality                   ($/kWh)
                                                              (1)
            37     NEW WAVERLY                             $0.002462
            38     NOME                                    $0.002026
            39     NORMANGEE                               $0.002524
            40     NORTH CLEVELAND                         $0.002534
            41     OAK RIDGE                               $0.002333
            42     ORANGE                                  $0.001987
            43     PANORAMA VILLAGE                        $0.002344
            44     PATTON VILLAGE                          $0.002505
            45     PINE FOREST                             $0.002521
            46     PINEHURST                               $0.002213
            47     PLUM GROVE                              $0.002444
            48     PORT ARTHUR                             $0.001617
            49     PORT NECHES                             $0.002320
            50     RIVERSIDE                               $0.002347
            51     ROMAN FOREST                            $0.002293
            52     ROSE CITY                               $0.002644
            53     ROSE HILL ACRES                         $0.002423
            54     SHENANDOAH                              $0.001767
            55     SHEPHERD                                $0.002431
            56     SILSBEE                                 $0.002375
            57     SOMERVILLE                              $0.002449
            58     SOURLAKE                                $0.002347
            59     SPLENDORA                               $0.001988
            60     TAYLOR LANDING                          $0.002026
            61     TODD MISSION
            62     TRINITY                                 $0.002425
            63     VIDOR                                   $0.002252
            64     WEST ORANGE                             $0.002435
            65     WILLIS                                  $0.002056
            66     WOODBRANCH VILLAGE                      $0.002453
            67     WOODLOCH                                $0.002219
            68     WOODVILLE                               $0.002312
            69       Total                                 $0.001965




_________________________________
Source: Response to TIEC 1-33 and 1-34.
                                                                                                         Exhibit JP-9
                                                                                                         Page 3 of 6     .




                                                ENTERGY TEXAS, INC.
                                                 Inside City kWh Sales
                                               Year Ended June 30, 2011


                                                                                       Large
                                             Small                      Large       Industrial
                                            General       General      General        Power
Line           Municipality   Residential   Service       Service      Service        Service    Lighting        Total
                                  (1)          (2)          (3)           (4)          (5)         (6)            (7)
 1     AMES                     6,157,021     206,883       301,282     1,999,200                 108,197        8,772,583
 2     ANAHUAC                 14,643,734    1,138,842    13,028,157                              284,537       29,095,270
 3     ANDERSON                 1,705,821     521,261      3,824,958                               37,461        6,089,501
 4     BEAUMONT               739,593,355   36,207,717   624,423,833 218,485,664    64,621,396 18,332,978 1,701,664,943
 5     BEDIAS                   2,448,073     330,732       618,998                                29,035        3,426,838
 6     BEVIL OAKS              10,929,135     145,053       808,011                                89,265       11,971,464
 7     BREMOND                  5,811,742     676,387      4,049,345                               72,105       10,609,579
 8     BRIDGE CITY             54,255,959    2,365,682    38,275,228    2,234,880                 623,076       97,754,825
 9     CALDWELL                   295,496       3,177        13,023                                      919      312,615
10     CALVERT                  7,323,896     900,284      3,854,934                              194,140       12,273,254
11     CHESTER                  1,023,056     115,158       611,019                                27,936        1,777,169
12     CHINA                   11,439,162    1,546,098     1,639,188                              113,125       14,737,573
13     CLEVELAND               38,674,992    4,830,930    41,530,606   17,136,056                1,104,650     103,277,234
14     COLMESNEIL               3,185,102     256,410      2,079,153                               61,064        5,581,729
15     CONROE                 303,187,965   31,025,071   329,345,475 120,579,498 172,314,355     4,635,593     961,087,957
16     CORRIGAN                 8,072,612     755,542      8,500,041                46,732,336    271,397       64,331,928
17     CUT AND SHOOT            4,353,035     613,855      2,462,696     508,000                  120,266        8,057,852
18     DAISETTA                 6,877,044     209,145      3,325,886    3,361,560                 104,579       13,878,214
19     DAYTON                  43,893,366    3,553,043    34,167,421   12,855,600   52,296,920    684,609      147,450,959
20     DEVERS                   2,802,857     289,972      1,171,681                               36,077        4,300,587
21     FRANKLIN                 9,714,801    1,024,375     9,830,777                              158,449       20,728,402
22     GROVES                 104,638,646    3,192,396    35,267,871    6,734,600 266,112,000    1,195,841     417,141,354
23     GROVETON                 6,194,245    1,023,700     5,460,351                              189,334       12,867,630
24     HARDIN                   6,695,543     490,882      3,148,276                               65,063       10,399,764
25     HOUSTON                 15,019,693    2,926,202    30,347,202   13,814,000                 354,874       62,461,971
26     HUNTSVILLE             154,587,193   12,877,624   120,983,287   45,081,770 107,136,710    2,292,012     442,958,596
27     IOLA                     2,152,582     270,022      1,412,372                               14,075        3,849,051
28     KOSSE                    3,087,571     428,273      1,706,604                               47,270        5,269,718
29     KOUNTZE                 14,304,369    1,337,112    11,153,925    1,583,640                 439,574       28,818,620
30     LIBERTY                  6,220,811     450,195      2,320,437                               77,233        9,068,676
31     LUMBERTON               90,711,776    3,931,661    31,476,995    7,225,040                 651,483      133,996,955
32     MADISONVILLE            25,155,651    2,461,356    24,906,844    1,811,520                 816,026       55,151,397
33     MIDWAY                   2,031,621     295,724       751,005                                24,831        3,103,181
34     MONTGOMERY               4,945,988    1,305,548    11,375,280    2,856,500                  98,217       20,581,533
35     NAVASOTA                37,902,545    2,714,620    32,056,026    1,897,536                 686,057       75,256,784
36     NEDERLAND              117,250,421    5,617,612    55,055,938   13,691,576                1,576,895     193,192,442




_________________________________
Source: Response to TIEC 1-33 and 1-34.
                                                                                                              Exhibit JP-9
                                                                                                              Page 4 of 6     .




                                                  ENTERGY TEXAS, INC.
                                                   Inside City kWh Sales
                                                 Year Ended June 30, 2011


                                                                                            Large
                                               Small                         Large       Industrial
                                              General       General         General        Power
Line            Municipality    Residential   Service       Service         Service        Service    Lighting        Total
                                    (1)          (2)          (3)              (4)          (5)         (6)            (7)
37     NEW WAVERLY                6,186,635     893,095      8,458,378                                 167,035       15,705,143
38     NOME                       4,274,651     267,434      1,075,381                   13,022,800     71,834       18,712,100
39     NORMANGEE                  4,685,684     733,269      3,259,918                                  80,407        8,759,278
40     NORTH CLEVELAND            1,417,547     196,521      1,122,735                                  31,110        2,767,913
41     OAK RIDGE                 15,512,527    1,109,742     8,622,905                                 178,742       25,423,916
42     ORANGE                   121,902,452    5,330,361    73,936,098      32,951,351                2,925,545     237,045,807
43     PANORAMA VILLAGE          16,815,453     172,616      1,876,527                                 110,436       18,975,032
44     PATTON VILLAGE             9,459,936     280,712      1,334,672                                  85,543       11,160,863
45     PINE FOREST                3,766,926     102,190       857,056                                   43,011        4,769,183
46     PINEHURST                 14,428,609    1,851,303    18,031,115                                 272,397       34,583,424
47     PLUM GROVE                 5,154,686     179,925       765,435                                   29,587        6,129,633
48     PORT ARTHUR              300,821,530   16,667,738   242,108,335      96,641,180 264,640,399    6,811,573     927,690,755
49     PORT NECHES               95,876,203    2,976,909    33,013,147       2,259,840    8,923,880   1,373,819     144,423,798
50     RIVERSIDE                  3,882,672     710,918      2,628,445                                  62,506        7,284,541
51     ROMAN FOREST              11,272,220     161,513      1,342,823                                  70,717       12,847,273
52     ROSE CITY                  3,894,546     891,367      3,433,309                                 196,318        8,415,540
53     ROSE HILL ACRES            3,574,730      24,623             7,027                               30,295        3,636,675
54     SHENANDOAH                17,151,497    3,571,029    66,710,837      39,257,020                 129,183      126,819,566
55     SHEPHERD                   9,663,780    1,200,889     7,036,184                                 169,837       18,070,690
56     SILSBEE                   44,893,519    2,807,085    33,187,092       7,331,904                 908,734       89,128,334
57     SOMERVILLE                 9,542,370     694,038      6,802,405                                 140,964       17,179,777
58     SOURLAKE                  13,320,335    1,150,526     4,819,631                                 314,910       19,605,402
59     SPLENDORA                 11,050,470    1,649,924    13,254,466                                 242,380       26,197,240
60     TAYLOR LANDING             2,520,441      10,643                                                 22,050        2,553,134
61     TODD MISSION                 225,749       8,849                                                       840      235,438
62     TRINITY                   16,729,022    1,881,546    12,391,053       2,062,320                 420,205       33,484,146
63     VIDOR                     75,343,633    5,062,074    39,005,260      14,398,460                1,075,229     134,884,656
64     WEST ORANGE               22,726,786    1,228,941     9,810,641      12,834,736                 398,808       46,999,912
65     WILLIS                    24,461,874    3,036,888    21,232,340       4,944,280                 548,569       54,223,951
66     WOODBRANCH VILLAGE        10,520,890     118,035       463,194                                   69,823       11,171,942
67     WOODLOCH                   1,879,191      43,548       241,443                                         880     2,165,062
68     WOODVILLE                 15,831,159    1,912,493    18,557,179       5,196,504                 527,683       42,025,018
69       Total                 2,766,074,601 182,965,286 2,126,669,153 689,734,231 995,800,791 53,129,207 6,814,373,283
70       Percent of Total            40.59%       2.68%        31.21%          10.12%        14.61%      0.78%




_________________________________
Source: Response to TIEC 1-33 and 1-34.
                                                                                                                 Exhibit JP-9
                                                                                                                 Page 5 of 6     .




                                                  ENTERGY TEXAS, INC.
                                    Municipal Franchise Fees By Customer Class
                                             Year Ended June 30, 2011


                                                                                         Large
                                                  Small                    Large      Industrial
                                                 General     General      General       Power
   Line           Municipality   Residential     Service     Service      Service       Service     Lighting       Total
                                     (1)           (2)         (3)          (4)          (5)          (6)           (7)
    1     AMES                      $15,090        $507          $738       $4,900             $0      $265         $21,501
    2     ANAHUAC                    31,027        2,413       27,604             0            0        603          61,647
    3     ANDERSON                     4,159       1,271        9,326             0            0            91       14,847
    4     BEAUMONT                1,591,901       77,933     1,344,010     470,269      139,091      39,460        3,662,664
    5     BEDIAS                       5,969         806        1,509             0            0            71        8,355
    6     BEVIL OAKS                 27,018          359        1,998             0            0        221          29,595
    7     BREMOND                    14,285        1,663        9,953             0            0        177          26,078
    8     BRIDGE CITY               130,107        5,673       91,785        5,359             0      1,494         234,418
    9     CALDWELL                         376           4           17           0            0            1              398
    10    CALVERT                    18,455        2,269        9,714             0            0        489          30,926
    11    CHESTER                      2,456         276        1,467             0            0            67        4,266
    12    CHINA                      28,314        3,827        4,057             0            0        280          36,479
    13    CLEVELAND                  90,136       11,259       96,791       39,937             0      2,574         240,698
    14    COLMESNEIL                   8,146         656        5,317             0            0        156          14,275
    15    CONROE                    532,428       54,483      578,364      211,750      302,601       8,141        1,687,767
    16    CORRIGAN                   19,220        1,799       20,238             0     111,265         646         153,168
    17    CUT AND SHOOT              10,387        1,465        5,877        1,212             0        287          19,228
    18    DAISETTA                   14,061          428        6,800        6,873             0        214          28,375
    19    DAYTON                     99,945        8,090       77,799       29,272      119,080       1,559         335,746
    20    DEVERS                       3,596         372        1,503             0            0            46        5,518
    21    FRANKLIN                   23,958        2,526       24,244             0            0        391          51,118
    22    GROVES                    100,055        3,053       33,723        6,440      254,456       1,143         398,871
    23    GROVETON                   15,501        2,562       13,665             0            0        474          32,201
    24    HARDIN                     16,787        1,231        7,893             0            0        163          26,073
    25    HOUSTON                    24,356        4,745       49,211       22,401             0        575         101,288
    26    HUNTSVILLE                294,473       24,531      230,461       85,876      204,085       4,366         843,792
    27    IOLA                         5,248         658        3,444             0            0            34        9,385
    28    KOSSE                        7,844       1,088        4,335             0            0        120          13,387
    29    KOUNTZE                    30,232        2,826       23,574        3,347             0        929          60,908
    30    LIBERTY                      8,212         594        3,063             0            0        102          11,972
    31    LUMBERTON                 219,272        9,504       76,087       17,465             0      1,575         323,902
    32    MADISONVILLE               58,676        5,741       58,095        4,225             0      1,903         128,641
    33    MIDWAY                       5,113         744        1,890             0            0            62        7,810
    34    MONTGOMERY                 10,833        2,860       24,915        6,257             0        215          45,080
    35    NAVASOTA                   86,240        6,177       72,937        4,317             0      1,561         171,232
    36    NEDERLAND                 277,766       13,308      130,428       32,435             0      3,736         457,673




_________________________________
Source: Response to TIEC 1-33 and 1-34.
                                                                                                                 Exhibit JP-9
                                                                                                                 Page 6 of 6   .




                                                 ENTERGY TEXAS, INC.
                                     Municipal Franchise Fees By Customer Class
                                              Year Ended June 30, 2011


                                                                                          Large
                                                 Small                      Large      Industrial
                                                General      General       General       Power
   Line            Municipality   Residential   Service      Service       Service       Service    Lighting       Total
                                      (1)         (2)          (3)           (4)          (5)         (6)           (7)
    37    NEW WAVERLY                 15,228      2,198       20,820               0            0       411          38,658
    38    NOME                          8,659       542         2,178              0      26,379        146          37,904
    39    NORMANGEE                   11,829      1,851         8,229              0            0       203          22,112
    40    NORTH CLEVELAND               3,591       498         2,844              0            0           79        7,013
    41    OAK RIDGE                   36,186      2,589       20,115               0            0       417          59,306
    42    ORANGE                     242,269     10,594      146,941         65,488             0     5,814         471,105
    43    PANORAMA VILLAGE            39,415        405         4,399              0            0       259          44,477
    44    PATTON VILLAGE              23,699        703         3,344              0            0       214          27,960
    45    PINE FOREST                   9,495       258         2,160              0            0       108          12,021
    46    PINEHURST                   31,932      4,097       39,905               0            0       603          76,537
    47    PLUM GROVE                  12,600        440         1,871              0            0           72       14,983
    48    PORT ARTHUR                486,428     26,952      391,489        156,269      427,924     11,014        1,500,076
    49    PORT NECHES                222,414      6,906       76,584          5,242       20,702      3,187         335,034
    50    RIVERSIDE                     9,113     1,669         6,169              0            0       147          17,098
    51    ROMAN FOREST                25,845        370         3,079              0            0       162          29,457
    52    ROSE CITY                   10,296      2,356         9,076              0            0       519          22,247
    53    ROSE HILL ACRES               8,663           60           17            0            0           73        8,813
    54    SHENANDOAH                  30,307      6,310      117,879         69,368             0       228         224,092
    55    SHEPHERD                    23,496      2,920       17,107               0            0       413          43,936
    56    SILSBEE                    106,604      6,666       78,806         17,410             0     2,158         211,644
    57    SOMERVILLE                  23,372      1,700       16,661               0            0       345          42,078
    58    SOURLAKE                    31,267      2,701       11,313               0            0       739          46,020
    59    SPLENDORA                   21,973      3,281       26,356               0            0       482          52,092
    60    TAYLOR LANDING                5,105           22            0            0            0           45        5,172
    61    TODD MISSION                      0           0             0            0            0           0              0
    62    TRINITY                     40,563      4,562       30,045          5,001             0     1,019          81,189
    63    VIDOR                      169,681     11,400       87,844         32,427             0     2,422         303,774
    64    WEST ORANGE                 55,331      2,992       23,885         31,247             0       971         114,426
    65    WILLIS                      50,299      6,244       43,658         10,166             0     1,128         111,495
    66    WOODBRANCH VILLAGE          25,805        290         1,136              0            0       171          27,402
    67    WOODLOCH                      4,171           97           536           0            0           2         4,805
    68    WOODVILLE                   36,608      4,422       42,912         12,016             0     1,220          97,179
    69      Total                  $5,653,887 $373,792 $4,290,189 $1,356,969 $1,605,583 $108,965 $13,389,386
    70      Percent of Total          42.23%      2.79%       32.04%         10.13%       11.99%      0.81%        100.00%




_________________________________
Source: Response to TIEC 1-33 and 1-34.
                                                                      Exhibit JP-10




                    ENTERGY TEXAS, INC.
                      Allocation Factors for
              Miscellaneous Gross Receipts Taxes
                 Test Year Ended June 30, 2011
                    (Dollar Amounts in 000's)



                                            Inside City Revenues
                                                         Percent of
  Line            Customer Class             Amount        Total
                                               (1)          (2)


    1      Residential Service               $313,368       49.90%
    2      Small General Service                20,935       3.33%
    3      General Service                     181,122      28.84%
    4      Large General Service                51,284       8.17%
    5      Large Industrial Power Service       54,309       8.65%
    6      Lighting Service                      7,006       1.12%
    7     Total                              $628,024      100.00%




(1) Source: ETI's Response to TIEC 10-1.
                                                                                                                                            Exhibit JP-11


                                                                ENTERGY TEXAS, INC.
                                            Revised Texas Retail Cost-of-Service Study at Present Rates
                                                   Excluding Purchased Power Capacity Costs
                                                          Test Year Ended June 30, 2011
                                                            (Dollar Amounts in 000's)

                                                                                                                                    Large
                                                                                      Small                         Large         Industrial
                                                       Texas                         General        General        General          Power
Line                   Description                     Retail        Residential     Service        Service        Service         Service        Lighting
                                                        (1)              (2)           (3)            (4)            (5)             (6)            (7)

 1     Total Adjusted Rate Base                       $1,720,671        $990,129       $55,113       $356,156       $120,249        $179,199        $19,825
       Revenues
 2     Total Adjusted Rate Schedule Revenues            634,114          325,744        22,562        135,404         42,430         100,483          7,490
 3     Other Sales For Resale Revenues                   55,967           27,841         1,232         10,577          4,154          11,993            170
 4     Provision For Rate Refund                              0                0             0              0              0               0              0
 5        Total Sales Revenue (L2 + L3 + L4)            690,081          353,585        23,794        145,981         46,584         112,476          7,661
 6     Other Operating Revenues                          47,821           25,539         1,270          9,681          3,552           7,500            279
 7        Total Adjusted Revenues (L5 + L6)             737,902          379,125        25,063        155,662         50,136         119,976          7,939

 8     Total Adjusted Operating Expenses                485,122          257,784        16,633         98,034         32,314          73,301          7,057

 9     Total Adjusted Operating Income (L7 - L8)       $252,780         $121,340        $8,430        $57,629        $17,823         $46,676              $883

10     Rate Of Return (L9 ÷ L1)                          14.69%           12.25%        15.30%         16.18%         14.82%          26.05%          4.45%

11     Relative Rate of Return (L10 ÷ 14.69%)                 100%             83%           104%           110%           101%            177%           30%

12     Interclass Subsidy                                       $0      ($37,487)            $519      $8,248              $245      $31,630         ($3,154)
                                                                     Exhibit JP-12




                      ENTERGY TEXAS, INC.
               ETI's Proposed Class Revenue Allocation
                     Test Year Ended June 30, 2011
                        (Dollar Amounts in 000's)




                                              Proposed
                                   Present      Base
                                  Non-Fuel    Revenue      Percent
Line           Rate Class         Revenues    Increase    Increase
                                     (1)         (2)        (3)

 1     Residential Service         $379,382     $81,769      21.6%
 2     Small General Service         26,430         411       1.6%
 3     General Service              159,768       7,500       4.7%
 4     Large General Service         49,380       8,084      16.4%
 5     Large Ind. Power Service     104,308      11,226      10.8%
 6     Lighting Service              10,813       2,199      20.3%
 7     Total                       $730,080   $111,189       15.2%
                                                                         Exhibit JP-13
                                                                           Page 1 of 2



                          ENTERGY TEXAS, INC.
                Recommended Class Revenue Allocation
                      Based on TIEC's Revised
                     Class Cost-of-Service Study
                    Test Year Ended June 30, 2011
                       (Dollar Amounts in 000's)



                                                      Recommended
                                         Present          Class
                                        Non-Fuel    Revenue Allocation
Line             Rate Class             Revenues     Amount Percent
                                          (1)          (2)       (3)


 1     Residential Service               $379,382    $80,390    21.2%
 2     Small General Service               26,430        283     1.1%
 3     General Service                    159,768      9,797     6.1%
 4     Large General Service               49,380      8,714    17.6%
 5     Large Industrial Power Service     104,308      9,862     9.5%
 6     Lighting Service                    10,813      2,143    19.8%
 7     Total                             $730,080   $111,189    15.2%
                                                                           Exhibit JP-13
                                                                             Page 2 of 2



                          ENTERGY TEXAS, INC.
               Recommended Class Revenue Allocation
                      Based on TIEC's Revised
                     Class Cost-of-Service Study
             and Proposed Schedule SMS/AFC Rate Design
                    Test Year Ended June 30, 2011
                       (Dollar Amounts in 000's)



                                                        Recommended
                                         Present            Class
                                        Non-Fuel      Revenue Allocation
Line             Rate Class             Revenues       Amount Percent
                                          (1)            (2)       (3)


 1     Residential Service               $379,382      $81,500     21.5%
 2     Small General Service               26,430          340      1.3%
 3     General Service                    159,768       10,205      6.4%
 4     Large General Service               49,380        8,860     17.9%
 5     Large Industrial Power Service     104,308       10,153      9.7%
 6     Lighting Service                    10,813        2,160     20.0%
 7        Total Rate Schedules           $730,080     $113,218     15.5%
 8     Schedule SMS/AFC Impacts           $13,816       ($2,029)   -14.7%
 9        Total Electricity Sales        $743,896     $111,189     14.9%




       Schedule SMS Impact                 ($1,039)
       Schedule AFC Impact                   ($991)
                                                                               Exhibit JP-14




                                          ENTERGY TEXAS, INC.
                                         Schedule LIPS Rate Design
                                Based on ETI's Proposed Revenue Requirement



                                           Revenue       Billing
                                          Requirement    Units       Unit      Proposed
 Line              Description               ($000)       (000)      Cost        Rates
                                               (1)         (2)        (3)         (4)

        Demand-Related Costs
  1     Production: Generation               $13,198
  2     Interruptible Credits                  1,126
  3     Purchased Power Capacity              56,456
  4     Transmission                          20,629
  5        Production/Transmission            91,408     10,791.0      $8.47      $7.07
  6     Distribution                             744        748.8      $0.99      $1.82
  7        Total Demand-Related Costs        $92,152

  8     Customer-Related Costs                 6,050        0.984     $6,148         $0


  9     Energy-Related Costs                 $11,986    5,301,215   $0.00226    $0.00614




Source: Schedule P-6.2
                                                                                      Exhibit JP-15
                                                                                        Page 1 of 2


                                    ENTERGY TEXAS, INC.
                           Derivation of Schedule SMS Charges
                    Based on ETI's Proposed Schedule LIPS Rate Design
                                 (Amounts in Thousands)



 Line                          Description                      Amount      Units        Source
                                                                  (1)        (2)           (3)

         Billing Load Charge:
  1      Schedule LIPS Production/Transmission Demand Charges      $7.07 /kW           Exh. JP-14
  2      SMS/LIPS Coincidence Ratio                                  12%               Exh. JP-16
  3      Schedule SMS: Transmission Delivery                       $0.82 /kW           L1 x L2
  4      Schedule LIPS Distribution Demand Charges                 $1.82               Exh. JP-14
  5      Schedule SMS: Distribution Delivery                       $2.64 /kW           L3 + L4

         Energy Charges:
 6       Schedule LIPS Non-Fuel Energy Charges                  $0.00614 /kWh          Exh. JP-14
 7       Relative Loss Factor: Transmission                        99.9%               Note A
 8       Off-Peak Energy Charge: Transmission                   $0.00614 /kWh          L6 x L7
 9       Relative Loss Factor: Distribution                       104.1%               Note A
 10      Off-Peak Energy Charge: Distribution                   $0.00639 /kWh          L6 x L9

 11      On-Peak Energy Charge                                  $0.00917               Page 2
 12      On-Peak Energy Charge: Transmission                    $0.00916 /kWh          L11 x L7
 13      On-Peak Energy Charge: Distribution                    $0.00955 /kWh          L12 x L7




                                                                           Relative
Note A   Energy Losses                                          Percent    Losses
         Schedule LIPS                                           1.8855%
         Transmission                                            1.7700%   99.9%
         Distribution                                            6.0428%   104.1%
         Source: P-7.2 Energy & Demand at Plant
                                                                                Exhibit JP-15
                                                                                  Page 2 of 2


                                 ENTERGY TEXAS, INC.
                  Derivation of On-Peak Schedule SMS Energy Charge
                  Based on ETI's Proposed Schedule LIPS Rate Design
                                (Amounts in Thousands)


                                                                                   Units
Line                           Description                          Amount        Source
                                                                      (1)           (2)


 1     LIPS Demand Costs                                               $7.07 /kW
 2     Demand Costs Recovered In Billing Load Charge                   $0.89 /kW
 3     Remaining Demand Costs to Collect in On-Peak Energy Charge      $6.18 /kW L1 - L2

 4     Weekdays Excluding Holidays                                       255
 5     On-Peak Hours Per Day                                               8
 6     On-Peak Hours                                                   2,040

 7     Additional On-Peak Energy Charge                             $0.00303 /kWh L3 ÷ L6
 8     Schedule LIPS Non-Fuel Energy Costs                          $0.00614 /kWh Exh. JP-14
 9     On-Peak Energy Charge                                        $0.00917 /kWh L7 + L8
                                                           Exhibit JP-16




               ENTERGY TEXAS, INC.
          Schedule SMS Coincidence Ratio



                                 Average
                     Average     Monthly
                       4CP        Billing    Coincidence
 Line     Period     Demand      Demand        Factor
                        (1)         (2)          (3)

  1        2007         47,600     441,154      11%

  2        2008         31,133     502,301       6%

  3        2009         25,017     516,532       5%

  4        2010         14,115     531,439       3%

  5        2011         57,468     497,199      12%

  6      Test Year      43,205     500,763       9%

  7     Average 2007-2011                        7%

  8     LIPS           668,467     899,246      74%

        Ratio of SMS to LIPS
  9     Coincidence Factor                      12%




Source: Response to TIEC 6-3.
                                                                                           Exhibit JP-17
                                                                                             Page 1 of 2




                                    ENTERGY TEXAS, INC.
                       Derivation of Option A Rider AFC Charge
                       At ETI's Proposed Revenue Requirements



                                                                                          Distribution
Line                   Description                       Rate       Transmission            Demand
                                                          (1)               (2)               (3)


 1     Method 1: Levelized Cost Analysis1                   1.20%

       Method 2: Revenue Requirement Analysis
                                       2
 2        Revenue Requirement ($000)                                        $114,237         $177,594
                                3
 3        Plant in Service ($000)                                           $905,579       $1,169,856
                            4
 4        Fixed Charge Rate                                 1.18%                 1.05%         1.27%


 5     Recommendation                                       1.20%




 1     Page 2.
 2     Schedule P-6.1.2.
 3     Schedule P-5.
 4     Line 2 ÷ Line 3 ÷ 12 (Weighted 39% Transmission/61% Distribution).
                                                                                                                                                                Exhibit JP-17
                                                                                                                                                                  Page 2 of 2
                                                                      ENTERGY TEXAS, INC.
                                            Derivation of Option A Monthy Charge: Levelized Cost Analysis

                             Book                              Tax                                                          Insurance         Total Annual
              Facility    Depreciation    Accumulated      Depreciation                Net Rate     Rate Base               & Property    Revenue Requirement
  Year      Investment      Expense       Depreciation        Rates        ADIT         Base        Rev Req      O&M           Tax        Amount      Percent
                (1)            (2)             (3)             (4)          (5)           (6)          (7)        (8)           (9)         (10)        (11)
     1           $1,000          $33.33         ($33.33)         3.750%      ($1.46)     $965.21      $111.17      $31.90         $9.76     $186.17   18.62%
     2           $1,000          $33.33         ($66.67)         7.219%    ($15.06)      $918.28      $105.76      $31.90         $9.76     $180.76   18.08%
     3           $1,000          $33.33       ($100.00)          6.677%    ($26.76)      $873.24      $100.58      $31.90         $9.76     $175.57   17.56%
     4           $1,000          $33.33       ($133.33)          6.177%    ($36.71)      $829.95        $95.59     $31.90         $9.76     $170.59   17.06%
     5           $1,000          $33.33       ($166.67)          5.713%    ($45.04)      $788.29        $90.79     $31.90         $9.76     $165.79   16.58%
     6           $1,000          $33.33       ($200.00)          5.285%    ($51.87)      $748.13        $86.17     $31.90         $9.76     $161.16   16.12%
     7           $1,000          $33.33       ($233.33)          4.888%    ($57.31)      $709.35        $81.70     $31.90         $9.76     $156.70   15.67%
     8           $1,000          $33.33       ($266.67)          4.522%    ($61.48)      $671.86        $77.38     $31.90         $9.76     $152.38   15.24%
     9           $1,000          $33.33       ($300.00)          4.462%    ($65.43)      $634.57        $73.09     $31.90         $9.76     $148.09   14.81%
    10           $1,000          $33.33       ($333.33)          4.461%    ($69.37)      $597.29        $68.79     $31.90         $9.76     $143.79   14.38%
    11           $1,000          $33.33       ($366.67)          4.462%    ($73.32)      $560.01        $64.50     $31.90         $9.76     $139.50   13.95%
    12           $1,000          $33.33       ($400.00)          4.461%    ($77.27)      $522.73        $60.21     $31.90         $9.76     $135.20   13.52%
    13           $1,000          $33.33       ($433.33)          4.462%    ($81.22)      $485.45        $55.91     $31.90         $9.76     $130.91   13.09%
    14           $1,000          $33.33       ($466.67)          4.461%    ($85.17)      $448.17        $51.62     $31.90         $9.76     $126.62   12.66%
    15           $1,000          $33.33       ($500.00)          4.462%    ($89.12)      $410.88        $47.32     $31.90         $9.76     $122.32   12.23%
    16           $1,000          $33.33       ($533.33)          4.461%    ($93.06)      $373.60        $43.03     $31.90         $9.76     $118.03   11.80%
    17           $1,000          $33.33       ($566.67)          4.462%    ($97.01)      $336.32        $38.74     $31.90         $9.76     $113.73   11.37%
    18           $1,000          $33.33       ($600.00)          4.461%   ($100.96)      $299.04        $34.44     $31.90         $9.76     $109.44   10.94%
    19           $1,000          $33.33       ($633.33)          4.462%   ($104.91)      $261.76        $30.15     $31.90         $9.76     $105.15   10.51%
    20           $1,000          $33.33       ($666.67)          4.461%   ($108.86)      $224.48        $25.85     $31.90         $9.76     $100.85   10.09%
    21           $1,000          $33.33       ($700.00)          2.231%   ($105.00)      $195.00        $22.46     $31.90         $9.76      $97.46    9.75%
    22           $1,000          $33.33       ($733.33)                    ($93.33)      $173.33        $19.96     $31.90         $9.76      $94.96    9.50%
    23           $1,000          $33.33       ($766.67)                    ($81.67)      $151.67        $17.47     $31.90         $9.76      $92.47    9.25%
    24           $1,000          $33.33       ($800.00)                    ($70.00)      $130.00        $14.97     $31.90         $9.76      $89.97    9.00%
    25           $1,000          $33.33       ($833.33)                    ($58.33)      $108.33        $12.48     $31.90         $9.76      $87.48    8.75%
    26           $1,000          $33.33       ($866.67)                    ($46.67)        $86.67        $9.98     $31.90         $9.76      $84.98    8.50%
    27           $1,000          $33.33       ($900.00)                    ($35.00)        $65.00        $7.49     $31.90         $9.76      $82.49    8.25%
    28           $1,000          $33.33       ($933.33)                    ($23.33)        $43.33        $4.99     $31.90         $9.76      $79.99    8.00%
    29           $1,000          $33.33       ($966.67)                    ($11.67)        $21.67        $2.50     $31.90         $9.76      $77.49    7.75%
    30           $1,000          $33.33     ($1,000.00)                      ($0.00)        $0.00        $0.00     $31.90         $9.76      $75.00    7.50%
Net Present Value              $394.20                                                                $810.83    $377.28       $115.46    $1,697.77
Levelized Payment                $33.33                                                                 $68.56     $31.90         $9.76     $143.56
Levelized % (Annual)              3.33%                                                                  6.86%      3.19%         0.98%      14.36%
Levelized % (Monthly)             0.28%                                                                  0.57%      0.27%         0.08%       1.20%

                 Inputs                     Current
Discount Rate                                    7.49% ETI proposed ROE and Capital Structure
Before-Tax Cost of Capital                      11.52%
Depreciation Rate                                3.33%            30 year life
Composite Income Tax Rate                       35.00%
Annual O&M                                      $31.90 Distribution O&M as a % of Gross Plant
Insurance & Property Tax                         $9.76 Expense as a % of Gross Plant Investment
O&M Ins & Prop Tax Growth Factor                 1.000
Assumed Investment                              $1,000

Source: Response to TIEC 1-51 b,c,d
                                               Exhibit JP-18
                                                 Page 1 of 2




         ENTERGY TEXAS, INC.
 Derivation of Option B Rider AFC Charge
 At ETI's Proposed Revenue Requirement



              Selected                Post
              Recovery   Recovery   Recovery
                Term       Term       Term
 Line          (Years)    Charge     Charge
                (1)        (2)        (3)


   1             1         10.88%      0.35%

   2             2          5.39%      0.35%

   3             3          3.92%      0.35%

   4             4          3.20%      0.35%

   5             5          2.76%      0.35%

   6             6          2.48%      0.35%

   7             7          2.28%      0.35%

   8             8          2.14%      0.35%

   9             9          1.97%      0.35%

  10             10         1.94%      0.35%




See Page 2.
                                                                                                                    Exhibit JP-18
                                                                                                                      Page 2 of 2


                                                 ENTERGY TEXAS, INC.
                           Derivation of Option B Monthly Charges: Levelized Cost Analysis



                                   Levelized Carrying Costs                               Monthly Charge
         Recovery                    Pretax                   Property Tax Depreciation            Property Tax
Line    Term Years Depreciation      Return      O&M          & Insurance and Return      O&M      & Insurance     Total
                         (1)           (2)         (3)            (4)           (5)       (6)          (7)          (8)

1             1        $1,000.00      $264.21      $31.90           $9.76        10.54%    0.27%           0.08%    10.88%
2             2          $500.00      $105.14      $31.90           $9.76         5.04%    0.27%           0.08%     5.39%
3             3          $333.33       $95.67      $31.90           $9.76         3.57%    0.27%           0.08%     3.92%
4             4          $250.00       $91.76      $31.90           $9.76         2.85%    0.27%           0.08%     3.20%
5             5          $200.00       $90.09      $31.90           $9.76         2.42%    0.27%           0.08%     2.76%
6             6          $166.67       $89.52      $31.90           $9.76         2.13%    0.27%           0.08%     2.48%
7             7          $142.86       $89.59      $31.90           $9.76         1.94%    0.27%           0.08%     2.28%
8             8          $125.00       $90.05      $31.90           $9.76         1.79%    0.27%           0.08%     2.14%
9             9          $111.11       $83.65      $31.90           $9.76         1.62%    0.27%           0.08%     1.97%
10           10          $100.00       $91.67      $31.90           $9.76         1.60%    0.27%           0.08%     1.94%
11     Post Recovery                               $31.90           $9.76                  0.27%           0.08%     0.35%
                                                                                 Exhibit JP-19




                                   ENTERGY TEXAS, INC.
                             Fixed Fuel Factor Loss Multiplier
                                Year Ended June 30, 2011




                                                                    Current
                                       Energy         New Loss       Loss       Percent
Line         Delivery Voltage          Losses         Multiplier   Multiplier   Change
                                         (1)             (2)          (3)         (4)

 1        Secondary                     8.8754%         1.023158     1.034603     -1.1%

 2        Primary                       6.0428%         0.996539     1.004911     -0.8%

 3        Transmission < 230 KV         2.3010%         0.961375     0.962921     -0.2%

 4        Transmission >= 230 KV        0.5774%         0.945178     0.945741     -0.1%

 5        System Average                6.4111%




Source:                             Schedule P-7.2.                Fixed Fuel
                                                                     Factor
ANDREWS                                                                                             111 Congress Avenue, Suite 1700
                                                                                                    Austin, Texas 78701
A'rTORNEYS         KU RT H. . LLP                                                                   512.320.9200 Phone
                                                                                                    512.320.9292 Fax
                                                                                                    andrewskurth.com


                                                                                                    Meghan Griffiths
                                                                                                    512~320.9214 Phone
                                                                                                    512.320.9292 Fax ··
                                                                                                    meghangrlffilhs@andrewskurth.com




                                                    April 30, 2012



Tracie Lowrey
Public Utility Commission of Texas
1701 N. Congress Ave.
Austin, Texas 78701

         Re:       PUC Docket No. 39896, SOAH Docket No. XXX-XX-XXXX, Application of Entergy
                   Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs, and Obtain
                   Deferred Accounting - TIEC Errata to the Direct Testimony of Jeffry Pollock

Dear Ms. Lowrey:

       Texas Industrial Energy Consumers submits the attached errata to the Direct Testimony of
Jeffry Pollock, which includes the revisions listed below, Please note that two pages of Mr.
Pollock's testimony that are affected by the errata contain highly sensitive information. Corrected
versions of the pages with highly sensitive information are attached separately and filed pursuant
to the protective order in this docket. However, it should be noted that the highly sensitive
information contained on those pages is not affected by the errata.

         Errata

               •    Page 9, lines 4-5

               •    Page 22, Table 1

               •    Page 23, line 2

               •    Page 25, lines 13-15

               •    Page 27, lines 6, 7, 12

               •    Page 39 - line 4
                                                                           SOAH Docket No. XXX-XX-XXXX
               •    Page 42, lines 17-18                                      PUC Docket No. 39896
                                                                        ENTERGY TEXAS, INC. RATE CASE
               •    Page 48, Table 4                                         TIEC Exhibit No.       \__D


AUS:653507.I                                                                                                                     1
Austin   Beijing    Dallas   Houston   London   New York   Research TrianQ(e Park   The Woodlands   Washinqton. DC
      \,.' ~-··
         '
             "
             J




Tracie Lowrey
April 30, 2012
Page2

                      •   Page 106, Exhibit JP-1

                                                   Verytruly yours,




cc:               All parties of record




AUS:653507.I                                                          2
.,




                                                                                   Jeffry Pollock
                                                                                   Direct Testimony
                                                                                   ERRATA- Page 9



     1                     For all of these reasons, the Commission should reject any post-test year

     2             adjustments that use Rate Year projections for Test Year costs as ET! has done. If

     3             the Commission were to make such post-test year adjustments, however, the proper

     4             adjusted amount of purchased power capacity costs is $238.51 million or $6.651 per

     5             kW-Month, which is a reduction of $37.735 million from ETl's request. 1 The $37.735

      6            million reduction is based on re-pricing Test Year capacity purchases under the

      7            known PP As.

      8            •   Transmission Equalization Payments

      9                    ETl's proposed post-test year adjustment to transmission equalization

     1O            payments should be rejected because ETI has failed to demonstrate that the

     11            requested pro-forma adjustment is known and measurable.                  Transmission

     12            equalization payments are a function of three variables: inter-transmission

     13            investment, ownership costs and responsibility ratios. Estimating these variables is

     14             susceptible to a host of uncertainties, such as the timing of new transmission

     15             investment, the cost of money, operating expenses, taxes and load growth, which

     16             determines the responsibility ratios. Further complicating the analysis is that such

     17             estimates require specific assumptions not on.ly for ETI, but for all Entergy Operating

     18             Companies.      Should the Commission decide that a pro-forma adjustment is

     19             appropriate, a reasonable approach would be to annualize the average monthly

     20             transmission equalization payments incurred by ETI from January through June 2011




          1
              Ail amounts are stated on a Total Company basis.

                                                                             1. Introduction, Qualifications
                                                                                             And Summary

                                                      J. POLLOCK
                                                      IN CO RPO RATEO




                                                                                                               3
                                                                                                              ·,

                                                                                  Jeffry Pollock
                                                                                  Direct Testimony
                                                                                  ERRATA· Page 22



 1   Q       HAVE YOU ANALYZED ETl'S PROPOSAL TO RECOVER PURCHASED POWER

 2           CAPACITY COSTS IN BASE RATES?

 3   A      Yes.    ETI is proposing to recover $276 million of "adjusted test yaar" purchased

 4           power capacity.costs in base rates.•


 5   Q       HOW WAS THE $276 MILLION DERIVED?

 6   A       ET! projected its capacity purchases under PPAs that would be in place during the

 7           Rate Year (june 2012-May 2013). It then substituted these Rate Year expenses for

 8          the Test Year expenses in determining ETl's overall cost of service in this

 9           proceeding.


10   Q.     ARE ETi'S RATE YEAR PURCHASES BASED ON THE SAME ASSUMPTiONS

11          AS ITS TEST YEAR POWER PURCHASES?

12   A      No. For example, the projected quantity of capacity purchases is clearly different in

13          the Rate Year than during the Test Year as shown in the table below.



                             ··• ·. _{:J~~'\!!),f.1~~fl!~l~;I~0tt~t~ft~;'-~i{.i
                                     Purchase              Test       Rate
                                                           Year       Year
                              Third Party Purchases         5,884     12,834
                              Affiliate Purchases          21,670     21,711
                              MSS-1 Payments                8,309      5,262
                                 Total                     35,863     39,807




     8
        Direct Testimony of Robert R. Cooper at 20. Another ETI witness, Mr. Considine, stated that the
     amount of purchased power capacity costs ETI is seeking 1D recover are the costs that were removed
     from the Test Year. However, $246.6 million of costs were removed from the Test Year (Considine at
     26 and Adjustment No. 24). This testimony is contradicted by Mr. Cooper's testimony.
                                                                     2. Revenue Requirement Issues

                                              J. POLLOCK
                                              !NCORPORATEO




                                                                                                          4
      ... -,
_.,

                                                                                        Jeffry Pollock
                                                                                        Direct Testimony
                                                                                        E~TA-Page23




               1        As can be seen, ETl's Rate_ Year purchases (39,807 MW-Months) would be riearly

               2        11 % higher than the corresponding Test Year purchases (35,863 MW-Months).


               3    Q   WHY ARE RATE YEAR PURCHASES HIGHER THAN TEST YEAR PURCHASES?

               4    A   Rate year purchases reflect the fact that ETI is projecting to serve additional load

               5        during the Rate Year. As discussed later, most of the $30 million spread between

               6        Rate Year ($276 million) and Test Year ($245 million) purchased power capacity

               7        costs is due to additional capacity purchases.       These additional purchases are

                8       primarily related to meeting future loads, while maintaining an appropriate reserve

                9       margin.


               10   Q   DID ETI MAKE ANY OTHER ADJUSTMENTS TO RATE YEAR PURCHASED

               11       POWER CAPACITY COSTS?

               12   A   No.   ETI did not recognize additional revenues from post-test year load growth.

               13       Thus, ETl's post-test year adjustment fajls to recognize all attendant effects. Further,

               14       rates would be set using Rate Year costs and Test Year sales. Thus, this approach

               15       would clearly violate the Matching Principle as previously discussed.


               16   Q   SHOULD ETl'S RATE YEAR PURCHASED POWER CAPACITY COSTS BE USED

               17       TO SET RATES IN THIS PROCEEDING?

               18   A   No. ETl's use of Rate Year expenses is not consistent with accepted ratemaking

               19       practices or this Commission's rules. For all of these reasons, ETl's proposed post-

               20       test year adjustments should be rejected. Rates should be set using actual Test

               21       Year expenses.


                                                                                2. Revenue Requirement Issues

                                                         J. POLLOCK
                                                         INCORPORATEO




                                                                                                                   5
                                                                                                    ._.


                                                                         Jeffry Pollock
                                                                         Direct Testimony
                                                                         ERRATA·Page25



 1       quantified Test Year per-untt costs (column 3) by dividing the· Te.st Year costs

 2       (column 1) by the corresponding amount of Test Year capacity purchases (column

 3       2).       Pro-forma adjustments were made solely to recognize changes in per-unit

 4       capacity costs associated with known P.PAs. The pro-forma untt costs are based on

 5       analysis of all known PPAs (column 4).


 6   Q   HOW DID YOU QUANTIFY THE PRO-FORMA ADJUSTMENTS?

 7   A   First, I categorized ETl's PPAs into three separate groups:

 8             •    Tnird-Party Purchases (line 3);
 9             •    Affiliate Purchases (line 4); and
10             •    Reserve Equalization Payments (line 5).

11       I then applied the unit costs of the known PPAs (column 4) to Test Year capacity

12       purchases (column 2).          This resulted in adjusted Test Year purchased power

13       capacity costs of about $250 million (line 6). This is slightly higher than ETl's actual

14       Test Year costs and about $26 million below ETl's proposed adjusted Test Year

15       expense ($276 million- $250 million).


16   Q   SHOULD         ANY     FURTHER ADJUSTMENTS           BE   MADE     TO TEST YEAR

17       PURCHASED POWER CAPACITY COSTS?

18   A   Yes. It is currently known that the EAl-WBL PPA will expire at the end of 2012. To

19       ensure that rates reflect ETl's going-forward costs, Test Year expenses should be

20       adjusted to recognize this known change.




                                                                2. Revenue Requirement Issues

                                              J.POLLOCK
                                              !NCORPORATEO




                                                                                                     6
'   ..

              Contains Highly Sensitive Information                                                                                                 Jeffry Pollock
                                                                                                                                                    Direct Testimony
                                                                                                                                                    ERRATA· Page 27



                                                                                                                                                                                -
         1             whether this agreement is prudent.                                                Until such time as the Commission has

         2            determined a new EAl-WBL PPA is prudent, no post-test year adjustment associated

         3            with such a potential contract should be made in setting base rates. 10


         4    Q       PLEASE SUMMARIZE YOUR RECOMMENDATION ON ETi'S ADJUSTED TEST

         5            YEAR OF PURCHASED POWER CAPACITY COSTS.

         6    A       Test Year adjusted purchased power capacity costs should be set at $238.51 million,

         7            or $6.651 per kW-Month ($238.51 million + 35,863 MW-Months + 1,000) on a Total

          8           Company basis.                        This is based on Test Year capacity purchases, and it reflects

          g           changes in the per-unit costs under all known PPAs. It also reflects the expiration of·

         10           the EAl-WBL PPA, which is currently scheduled to occur during the Rate Year. The

         11           $238.51 million represents a $37.735 million reduction in ETl's proposed adjusted

         12           Test Year expense.


         13   Transmission Equalization Payments

         14   Q        WHAT ARE TRANSMISSION EQUALIZATION PAYMENTS?

         15   A        The Entergy System Agreement (ESA) requires that all Entergy Operating.

         16            Companies equalize certain transmission costs.                                                                  The equalization process is


              10
                  However, if an adjustment is to be made, It should not exceed $5.944 million, which is derived as
              follows:
                      .Line:_ "-' .·...,·: ,,··.'::.·. ·: D'$ilc~ipti()ni\•'.':;:.::.•:. '"-'•'''"':''' .@filQiif' .: ·.  ,.,,<·· ·,
                                                                                                                              :;:·:·.:·l'li:!tlriiJ;l~':,~:r,.;·;..,:;,. ;:.,
                         1     Demand Charge Differential Between                                                  ...Qerived from ETl's Responses
                               the Original and New EAl-WBL                                                          To TIEC 5-1 (Addendum 1).
                               Anreements Iner kW-fvbnth\
                         2     EAl-WBL Purchases Removed                                                  746         Exhibit JP-2, line 2.
                                   (MW-11/onths\
                          3        Adjustment (Millions)                                               $5.944           Line 1 x Line 2.

              This ooutd result in adjusted Test Year purchased power cai;acity costs of $242.080 millbn, which is a reductbn
              of $34.162 milrlOn from ETl's request
                                                                                                                                   2. Revenue Requirement Issues

                                                                                        J.POLLOCK
                                                                                        INCORPORATEO




                                                                                                                                                                                    7
                                                                           Jeffry Pollock
                                                                           Direct Testimony
                                                                           ERRATA - Page 39




 1        the deficient accounts-will require a $1.3 million increase In the annual accruals_ to

 2        achieve full recovery over the remaining lives of the surplus accounts. Thus, the net

 3        impact of my recommended adjustments to ETl's Test Year depreciation expense

 4        would be $0.794 million, as shown in the following table.




                                                         Amount
                                                      ($ in Millions)
                         Function
                                             Accruals Adjusted
                                             As Filed Accruals Difference
              General - Depreclable Accounts   $1,605      $2,946     $ 1,341
              General -Amortization Accounts   $5,947      $5,947     $     0
              Deficient Reserve Amortization        $2,135       $     0    ($2,135)
              General Plant Total                   $9,687       $8,893     ($ 794)

 5   Q    PLEASE SUMMARIZE YOUR RECOMMENDED DEPRECIATION EXPENSE.

 6   A    The Commission should reject ETl's proposal        to increase production depreciation
 7        rates at this time given that the production depreciation reserve has a considerable

 8        surplus. The Commission should also reject ETl's proposed general plant "catch-up•

 9        adjustment because the deficiency can largely be cured by reallocating the reserve

10        from the surplus to the deficit genera1 plant accounts. This recommendation reduces

11        ETl's proposed depreciation expense by $1.950 million ($1, 156,000 + $794,000) on

12        a Total Company basis.

13   Property Tax Expense

14   Q    IS ETI PROPOSING TO ADJUST PROPERTY TAX EXPENSES?

15   A    Yes. ETI is proposing a $2.6 million pro-fonma adjustment to Test Year expense.



                                                                 2. Revenue Requirement Issues

                                          J.POLLOCK
                                          !NCOftPOftATEO




                                                                                                   8
.,




          Contains Highly Sensitive Information                                  Jeffry Pollock
                                                                                 Direct Testimony
                                                                                 ERRATA· Page 42

     1             Entergy, the parent of ETI, should be disallowed on the basis that it benefrts only

     2.            shareholders not customers. As discussed later, ~t least $6.2 million of expense was

     3             incurred to achieve financial objectives and should be disallowed. This includes

     4             incentive compensation associated with affiliate (i.e., Entergy Services, Inc.)

     5        ..   expenses.


     6    Q        WHAT     INCENTIVE      COMPENSATION         PLANS     DOES     ETI   OFFER      ITS

     7             EMPLOYEES?

      8   A        ETI and ESI have two primary types of incentive compensation plans:

      9               1. Annual; and
     1O               2. Long-Term.

     11            These plans and proposed Test Year expenses are listed on Exhibit JP-7.


     12   Q        WHAT ARE THE ANNUAL INCENTIVE COMPENSATION PLANS?

     13   A        There are various annual incentive compensation plans including the Management

     14            Incentive Plan, Exempt Incentive Plan, Teamsharing Incentive Plan, Teamsharing

     15            Selected Bargaining Units Incentive Plan and Operational Incentive Plan.           In

     16            addition, there is also an Executive Annual Incentive Plan ("EAIP") for Entergy

     17            Company officers.


     18   Q        WHAT PERFORMANCE GOALS TRIGGER ADDITIONAL PAYOUTS UNDER THE

     19            ANNUAL PLANS?


     20   A        In general, the payouts under the Annual plans are based on cost control,

     21            operational and safety measures. In addition,        of the ESI portion of the EAIP is

     22            related to financial measures such as earnings per share (EPS) and stock price.2°

          "" Exhibit KGG-4 (Highly Sensitive).
                                                                        2. Revenue Requirement Issues

                                                   J. POLLOCK
                                                   INCORPORATEO




                                                                                                            9
                                                                                    Jeffry Pollock
                                                                                    Direct Testimony
                                                                                    ERRATA - Page 48




                     ~~,~~~:_,,~~;~!(~~,.~-~~i.~~.~~tWtillflf~,. -~- '~i~~l1i:::·~~~j~tt~.[~~N~.
                         38663       Informational Project Relating To Filings By Entergy
                                     Texas At The Louisiana Public Service Commission
                                     Relating To The Entergy System Agreement And
                                     Possible Successor Arrangements
                         38708       Project To Investigate The Entergy SuGCSssor
                                     Arrangement
                         37344       Information Related To The Entergy Regional State
                                    ·Committee
                         37338       Commission Review Of Wholesale Market Issues
                                     Relating To Entergy Texas, Inc.

 1   Q           WHY ELSE SHOULD ETl'S PROPOSED DEFERRED ACCOUNTING REQUEST

 2                BE DENIED? .

 3   A           The projected transition costs are not material. ETI is currently projecting to incur

 4                $17 million of transition costs.28 This equates to only $5.8 million per year, which Is

 5               only 1% of ETI's Test Year operating revenues.           Even at this level, the MISO

 6               transition costs are easily subsumed in the normal variation in ETl's year-to-year

 7               expenses._ as shown In Exhibit JP-8.


 8   Q           PLEASE EXPLAIN EXHIBIT JP-8.

 9   A            Exhibit JP-8 measures the year-to-year variation in operating expenses booked to

1o               those FERG Accounts In which ETI Is proposing to record the MISO transition costs.

11               The year-to-year varlatlon is calculated for 3 separate time periods:

12                        1. Calendar year 2009 versus year 2008;
13                       2. Calendar year 201 O versus year 2009; and
14                        3. Docket No. 39896 versus Docket No. 37744.


     2
         '   Supplemental Direct Testimony of Jay Lewis at 5.

                                                                          2. Revenue Requirement Issues

                                                    J.POLLOCK
                                                    !NCO!tPORATEO




                                                                                                            10
.,



                                                                                  ExhibitJP-i ERRATA



                                          ENTERGY TEXAS, INC.
                                      Derivation of Test Year Adjusted
                                      Purchased Power Capacity Costs
                                         Year Ended June 30, 2011


                                                        Amount           Unit Cost
                                           Test Year     (MW·         ($/kW-Month)             Cost
     Line              Descri[!tion          Cost       Months)     Actual     Pro .. Forma   ($000)
                                              (1)         (2)        (3)             (4)       SS)

      1     ETI Proposed Expense                                                              $276,242

      2     Test Year Actual Expense                                                           245,433

            Pro·Forma Adjustments (a)
     '3     Third Party Purchases             $30,939      5,884      $5.258       $5.381            723
      4     Affiliate Purchases               189,032     21,670         8.723       8.656      (1,462)
      5     Reserve Equalization               25,461       8,309        3.064       3.659       4,944
      6        Total                         $245,433     35,863      $6.844       $6.940      249,638
            Adjust Unit Cost
            for Expiration of the
      7     EAl·WBL Contract (b)                                                               (11,132)

      8     Test Year Adjusted                                                                 238,507

      9     Adjustment to ETl's Proposal                                                      ($37,735)




     (a)    Column 5 =(Column 4 ·Column 3) x Column 2.
     (b)    Exhibit JP-2.




                                                                                                           11
                    DOCKET NO.    Joi 9/Jf
APPLICATION OF ENTERGY        §           BEFORE THE
GULF STATES, INC. FOR         §    PUBLIC UTILITY COMMISSION            I"-)
DETERMINATION OF HURRICANE    §            OF TEXAS                     =
                                                                        c..-:>
                                                                        C".;M
RECONSTRUCTION COSTS          §                                         <-
                                                                        c:::              "'
                                                                   ,,
                                                                        • I
                                                               "        c•.n       c'"''"t
                                                                                 ' " ,,~
                                                                                          ,,
                                                                        -ry
                                                               '        ..;...           .,'
                                                                                    .,    ~

                                                                        r;y



           APPLICATION OF ENTERGY GULF STATES, INC.

                    FOR DETERMINATION OF

              HURRICANE RECONSTRUCTION COSTS




                         JULY 5, 2006




Hurr Recon Costs                                                          1-001

                              1
                                                                                               I
        This page intentionally left blank.




Hurr Recon Costs                              1-002

                         2
                      ENTERGY GULF STATES, INC.
                HURRICANE RECONSTRUCTION COSTS CASE
                    EXECUTIVE SUMMARY OVERVIEW
      Entergy Gulf States,      Inc. ("EGSI" or the "Company") requests a
determination by the Commission that its EGSI Texas retail-jurisdictional
Hurricane Rita reconstruction costs of $393,236,384 were reasonable and
necessary to enable EGSI to restore electric service to its Texas customers. With
this determination, EGSI requests entry of a Commission order: (a) determining
that such costs are eligible for recovery and securitization; (b) authorizing the
Company to recover carrying costs; and (c) approving the manner in which
hurricane reconstruction costs will be functionalized and allocated in a subsequent
proceeding.

      EGSI proves up the reasonableness and necessity of the $393.2 million by
showing that, on a Total Company basis (that is, EGSI Texas and EGSI Louisiana
combined), EGSI incurred $561.0 million in Hurricane Rita reconstruction costs
based on the following functional cost classes:

  Class (Type) of Cost         Texas Retail Costs         Total Company Costs
      Transmission                $36.7 million                $80.6 million
        Generation                 $5.1 million                $11.9 million
   Other Plant/Suooort             $1.1 million                 $2.4 million
    Distribution-Texas           $350.3 million               $355.6 million
  Distribution-Louisiana               -0-                    $110.4 million
           Total                 $393.2 million               $561.0 million

Sorted another way, the $393.2 million (Texas Retail) and the $561.0 million (Total
Company) include the following categories of costs within the functional cost
classes:

          Cost Category         Texas Retail Costs         Total Company Costs
Non-Enterav Contractors           $307.2 million               $428.3 million
EGSI Employee Expenses             $13.7 million                $19.3 million
EGSI Labor                          $9.4 million                $15.6 million
Materials                          $36.2 million                $55.1 million
Other Costs/Telecommunications/    $18.1 million                $28.1 million
Transportation
Affiliate Charges (ES I/Loaned      $8.6 million                $14.5 million
Resources
              Total               $393.2 million               $561.0 million


                                         1


Hurr Recon Costs                                                                      1-003

                                         3
       Eleven witnesses support the Company's case.            Their proof includes:
detailed explanations of why and how the costs were incurred; the extraordinary
scope of damage; cost controls, including oversight of contractors; reliance on pre-
existing competitively-bid or negotiated contracts where possible; the need for
quick and safe restoration; benchmarks comparing EGSI Texas' restoration efforts
to other utilities; the cost recording, accounting, and review process; an
independent third-party financial audit of the costs; affiliate cost proof discussion;
potential insurance and grant payments; and a financial ratings agencies
perspective.
       Because of the 150-day processing timeline established by House Bill 163
for this case, and its unique nature, EGSI requests that the Commission hear this
case directly.
       The Commission's decision in this case concerning EGSl's reasonable and
necessary costs associated with Hurricane Rita will define for the future the level
of urgency a utility should employ in restoring service after a major weather event.
The Commission should strive to create an incentive for Texas utilities to follow
EGSl's example in taking all actions reasonably available to restore service as
quickly as possible for the benefit of customers and the regional economy.




                                          2


Hurr Recon Costs                                                                         1-004

                                           4
~----   -- -   .......---




                                                             DOCKET NO.

                        APPLICATION OF ENTERGY                       §                BEFORE THE
                        GULF STATES, INC. FOR                        §         PUBLIC UTILITY COMMISSION
                        DETERMINATION OF HURRICANE                   §                 OF TEXAS
                        RECONSTRUCTION COSTS                         §


                               APPLICATION OF ENTERGY GULF STATES, INC. FOR DETERMINATION OF
                                             HURRICANE RECONSTRUCTION COSTS

                        TO THE HONORABLE PUBLIC UTILITY COMMISSION OF TEXAS:

                                                        I.      EXECUTIVE SUMMARY
                            Entergy Gulf States, Inc. ("EGSI or the "Company") requests a determination by the

                            Public Utility Commission of Texas ("Commission") that its EGSI Texas retail-

                        jurisdictional Hurricane Rita reconstruction costs of $393,236,384, through March 31,

                            2006, were reasonable and necessary to enable EGSI to restore electric service to its

                        Texas customers. With this determination, EGSI requests entry of a Commission order:

                            (a) determining such costs are eligible for recovery and securitization; (b) authorizing

                            the Company to recover carrying costs; and (c) approving the manner in which

                            hurricane reconstruction costs will be functionalized and allocated in a subsequent

                            proceeding.

                                  Hurricane Rita was the most severe natural disaster ever to hit EGSl's service

                            area in southeast Texas and southwest Louisiana.         The storm severely damaged

                            distribution and transmission facilities in Texas as well as causing damage to a majority

                            of EGSl's generation resources. At the storm's peak, over 75% of the customers in

                            EGSl's Texas service area were without service. Working with neighboring utilities,

                            EGSI undertook significant efforts to restore service to its customers, managing to

                            restore service to all customers who could receive service within 21 days. The costs of




                             Hurr Recon Costs                                                                           1-005

                                                                         5
EGSl's reconstruction for both its Texas and Louisiana jurisdictions totaled almost $561

million through March 31, 2006. Of this amount, $393.2 million was incurred in Texas

retail-jurisdictional costs for the same time period.

          EGSI files this Application as authorized by House Bill 163, which the Texas

Legislature passed and the Governor signed into law in May 2006.            House Bill 163

states that EGSI is entitled to recover hurricane reconstruction costs consistent with the

Bill. The Bill provides a detailed, specific definition of the term "hurricane reconstruction

costs."     Summarized, the "hurricane reconstruction costs" that EGSI is entitled to

recover are: the reasonable and necessary costs, whether expensed, charged to the

storm reserve, or capitalized, that EGSI incurred due to its own activities or activities

conducted on its behalf by others, in connection with the restoration of service

associated with electric power outages affecting EGSl's customers as a result of

Hurricane Rita. The Bill states that these costs include costs for "mobilization, staging,

and construction, reconstruction, replacement, or repair of electric generation,

transmission, distribution, or general plant facilities." House Bill 163 also states that the

hurricane reconstruction costs may include carrying charges, and that EGSI is enabled,

through the Bill, to use securitization financing to obtain timely recovery of the

reconstruction costs.     EGSI requests the recovery of carrying costs on its Hurricane

Rita expenditures and, in a future proceeding after the total Hurricane Rita

reconstruction costs are determined in this docket, will request a securitization financing

order to recover those costs.

          EGSl's request for a determination of its Texas retail Hurricane Rita

reconstruction costs incurred includes testimony and supporting exhibits sponsored by



                                              2




  Hurr Recon Costs                                                                              1-006

                                               6
eleven witnesses. As is typical in cost-related applications filed by EGSI before the

Commission, the majority of EGSl's witnesses focus on and support the Total Company

costs: in this case, that is, the $561 million Total Company figure. The reason for this

approach is that EGSl's books and records are maintained on a Total Company basis.

The costs are recorded for the single legal entity -   EGSI -   rather than its two distinct

internal functional operations -   EGSI Texas and EGSI Louisiana. EGSI also presents

witnesses who explain how to derive the Texas retail costs (the $393.2 million) from the

Total Company $561 million Hurricane Rita costs.

       Because of the 150-day processing timeline established by House Bill 163 for

this case, and its unique nature, EGSI also requests that the Commission hear this case

directly.

                       A.     Summary of Reconstruction Costs

       At a summary level, the costs in this case are presented both by "class" of cost

and by "category" of cost. In this Application, a class of cost is a distinct operational or

functional grouping: transmission, generation, distribution, and "other plant/support." A

"category" of cost is a different view that shows different types of activities or services

that would be common to each of the classes -            for example, external/third-party

contractor costs; materials, telecommunications, etc. The following table shows the

Hurricane Rita reconstruction costs, exclusive of carrying costs, by functional class at

both the Texas Retail and at the Total Company levels:




                                             3




  Hurr Recon Costs                                                                             1-007

                                             7
  Class (Type) of Cost                 Texas Retail Costs                Total Company Costs
       Transmission                       $36. 7 million                      $80.6 million
        Generation                        $5.1 million                        $11.9 million
   Other Plant/Suooort                    $1.1 million                         $2.4 million
    Distribution Texas                   $350.3 million                      $355.6 million
  Distribution Louisiana 1                     -0-                           $110.4 million
            Total                        $393.2 million                       $561 million


       The following table shows the categories of Hurricane Rita reconstruction costs

at both the Texas Retail and the Total Company levels:

            Cost Category                    Texas Retail Costs          Total Comoanv Costs
Non-EnterQV Contractors                         $307 .2 million                $428.3 million
EGSI Employee Expenses                           $13.7 million                  $19.3 million
EGSI Labor                                       $9.4 million                   $15.6 million
Materials                                        $36.2 million                  $55.1 million
Other Costsffelecommunications/                  $18.1 million                  $28.1 million
Transportation
Affiliate CharQes                                 $8.6 million                   $14.5 million
                Total                            $393.2 million                  $561 million


       The Company's presentation in this Application, however, is much more than

simply dollar amounts segregated in different ways.           The Company's witnesses provide

detailed explanations as to:

   •   why Hurricane Rita was so destructive and thus costly;

   •   the unique issues faced by EGSI in the reconstruction; and

   •   the systems and practices in place or implemented in response to the storm to

       monitor, control, and reduce costs, while also expediting reconstruction in a safe

       and organized manner.


   1
      EGSI Texas is not requesting recovery of any Distribution Louisiana costs; this amount is included
   in the $561 million Total Company figure as part of the Hurricane Rita reconstruction costs incurred
   by EGSI, but it is not in the $363.2 million specifically requested by EGSI Texas in this filing.

                                                  4




  Hurr Recon Costs                                                                                         1-008


                                                   8
                              B.    Summary of Witnesses

       In this Application, three witnesses directly support the reasonableness and

necessity of the Hurricane Rita reconstruction costs based on the four functional cost

classes:

   •   Joseph F. Domino, President and CEO of Entergy Texas, sponsors the

       Generation class and the Other Plant/Support class;

   •   Randall W. Helmick, Vice President for Transmission Services of Entergy

       Services, Inc. (ESI), sponsors the Transmission class; and

   •   John E. Mullins, Director of Distribution Operations for EGSI Texas sponsors the

       Distribution- Texas.

       The following three Company witnesses explain the proposed regulatory

treatment of the hurricane reconstruction costs, the detail to move from the $561 million

in Total Company costs down to the $393.2 million in Texas retail costs, and then

propose how those Texas costs should be functionalized and then allocated to the

Texas retail customers:

   •   J. David Wright, Directory of Regulatory Accounting with ESI, addresses:

       accounting practices for identifying costs and deriving the Texas retail cost figure

       from the Total Company cost; regulatory asset treatment of the Texas retail cost;

       and request for carrying costs;

   •   Myra L. Talkington, Senior Staff Rate Analyst with ESI, addresses allocation of

       costs to the Texas retail jurisdiction and among the Texas retail jurisdiction rate

       classes and schedules; and




                                            5




  Hurr Recon Costs                                                                            1-009

                                             9
   •   Donald W. Peters, Manager, Revenue Requirements for ESI, addresses how the

       Company proposes to apply allocation methods and factors.

       The   remaining    five   EGSI    witnesses   provide   further   support for the

reasonableness and necessity of the Hurricane Rita reconstruction costs as follows:

   •   Theodore H. Bunting. Jr., Vice President, CFO-Operations with ESI, addresses

       internal cost compilation, review, approval and recording practices;      the "not

       higher than" and "at cost" prongs of the Texas affiliate cost recovery standard;

       and the status of potential insurance and grant payments;

   •   Michael A. Herman, a partner with PricewaterhouseCoopers, provides an

       external attestation review of the Company's storm reports;

   •   Steven M. Fetter, President of an external utility advisory firm, addresses credit

       ratings and how this proceeding can affect EGSl's credit ratings;

   •   John P. Hurstell, Vice President of Entergy Management, System Planning and

       Operations with ESI, describes the financial stress imposed by Hurricane Rita on

       EGSI, and the effect on EGSl's ability to transact with fuel and purchased power

       suppliers; and

   •   Grant L. Davies, CEO of Davies Consulting, Inc., provides an external

       assessment of the magnitude of Hurricane Rita, EGSl's performance prior to and

       during the Hurricane Rita reconstruction, and EGSI Texas' resource acquisition

       strategy.

                                 C.     Summary of Proof

       The proof of why the Company's Hurricane Rita reconstruction costs were

"reasonable and necessary" is led by the three cost class witness: Messrs. Domino,


                                             6



  Hurr Recon Costs                                                                          1-010

                                            10
Helmick, and Mullins. The bullet points below are derived primarily from the testimony

and exhibits of those three witnesses. The remaining witnesses, however, are also

crucial to the ultimate proof that the Company's claimed costs were, in fact and in law,

reasonable and necessary.

   •   Hurricane Rita made landfall east of Sabine Pass in the early morning hours of

       September 24, 2005 and tracked northward along the Texas/Louisiana border,

       producing damaging and sustained hurricane and tropical storm force winds until

       the early hours of September 25.

   •   The Beaumont area, for example, experienced sustained winds of 81 mph and

       wind gusts of 105 mph with isolated reports up to 120 mph along with nine inches

       of rain during Hurricane Rita's life.

   •   At the peak of outages, 286,609 of EGSl's Texas customers were without

       electricity.

   •   Mr. Mullins testifies, based on his 21 years of experience as a first responder to

       several storm events, that Hurricane Rita cut one of the widest paths he had

       experienced, and that the damage was comparable to hundreds of tornadoes

       sweeping through southeast Texas.

   •   Despite Hurricane Rita being the most destructive storm to hit EGSl's Texas

       service territory in recent history, the Company, with the assistance of many

       outside contractors, was able to restore service to its entire system in only three

       weeks. This was achieved through pre-established plans and training, thoughtful

       deployment and reaction, and overall coordinated and management under

       EGSl's direction and control.



                                               7




  Hurr Recon Costs                                                                           1-011


                                               11
•   Before and during the storm, pre-established teams were mobilized to staging

    areas with initial materials to begin restoration as soon as safely possible.

    Internal communications and links with weather services and other first

    responders and officials were established.        Company witness Domino, in

    particular, discusses the intensive communications established between EGSI,

    its customers, and the Commission and State government to coordinate and

    keep all parties informed and involved.

•   During and immediately after the hurricane, a priority was to safely and timely

    mobilize our internal crews, and to secure outside crews from other utilities and

    third-party contractors, to restore service as soon as possible. In all, over 11,000

    workers were mobilized and coordinated by EGSI to restore service and

    reconstruct its electric system as a result of the damage caused by Hurricane

    Rita.

•   The initial reconstruction efforts were done in accordance with a pre-established

    storm plan that anticipates natural disasters such as Hurricane Rita. Training

    related to the storm plan and its execution is conducted at least annually as part

    of the Company's annual system storm drill.

•   EGSI, on a daily basis throughout the reconstruction effort, determined the

    number of crews and resources needed throughout its Texas territory for the

    reconstruction effort. This effort was coordinated between the distribution and

    transmission functions to ensure that distribution reconstruction was taking place

    in areas where transmission would be available and could support load. Crews




                                          8



Hurr Recon Costs                                                                           1-012


                                         12
    were deployed and released as necessary to achieve the work needed without

    waste or duplicate efforts.

•   A high priority was to re-establish the transmission grid so that power could flow

    to reconstruct the damaged substations, and then on to the distribution feeders

    as they were repaired.

•   The crews faced significant reconstruction obstacles caused by: (1) the

    hurricane, such as downed trees and debris across roadways, rights-of-way, and

    work sites, and soft ground from the heavy rain and flooding, which prevented

    truck access; (2) the original location of now-damaged equipment and downed

    lines behind buildings or in alleys; and (3) operational obstacles, such as the

    availability and access to staging areas that were being occupied by different

    groups of first responders, and the logistics of EGSI managing the mobilization,

    feeding, and lodging of internal and external reconstruction crews.

•   Reconstruction as quickly as possible, but also as safely as possible, was critical

    to get basic human services back up and running, such as hospitals, water and

    sewage facilities, the Department of Energy's Strategic Petroleum Reserve,

    petrochemical plants, and interstate natural gas pipeline pumping stations.

    Reconstruction costs could potentially have been reduced if service restoration

    had been prioritized on a slower track.      But a slower track would have been

    detrimental to the local, State, and national economies, and was not favored by

    the local, State, and federal authorities.

•   Company witnesses Domino, Helmick, and Mullins explain in detail what types of

    costs were incurred within their respective functional cost classes, and within the



                                           9




Hurr Recon Costs                                                                          1-013

                                           13
    cost categories within their classes, and why these costs were incurred at the

    stated levels.

•   Contract work provided by third-party independent contractors and non-Entergy

    utilities make up a majority of the reconstruction costs. Crews were brought in

    from as far away as New York State to assist in the effort, and this just a month

    after Hurricane Katrina had destroyed vast areas along the Gulf Coast and New

    Orleans.

•   Independent (third-party) contractor companies were needed to assist in the

    emergency reconstruction. These contractors were needed to assist Company

    crews to: repair damaged electrical infrastructure, remove or trim back downed

    vegetation, provide emergency logistics support (including transportation, food

    and housing) and other emergency, short-term services. Many of the contracts

    with these vendors had been negotiated prior to the 2005 hurricane season and

    executed at pre-storm, competitive rates.       Additional independent contractors

    who were not pre-signed with EGSI were needed for the reconstruction; their

    rates were also negotiated at competitive rates that took into account the

    contractors' skills, capabilities, work product, and safety practices.

•   Utilities not affiliated with EGSI sent crews to assist in the reconstruction effort.

    The "mutual-aid" utilities services were paid for at the cost incurred by those

    utilities, without markup.

•   EGSl's affiliated utilities also sent "loaned resource" crews to assist in the

    reconstruction effort. These affiliated crews (and others) were just coming off, or




                                          10



Hurr Recon Costs                                                                            1-014

                                          14
     being redeployed from, the restoration efforts from Hurricane Katrina. They were

     also reimbursed at their normal pay level with no markup.

•    In addition to prudent contracting practices, EGSI was able to increase

     productivity and decrease restoration time by staging crews close to their

     designated repair sectors and engaging in night-time refueling and equipment

     maintenance.

•    The Company's witnesses accurately refer to the combined groups of EGSI

     employees, affiliated utility employees, mutual aid utility employees, and third-

     party contractors as an "army." In this case, a specialized and competent, well

     organized and managed army that worked individual extended shifts of up to 16

     hours per day.

 •   Company witness Davies provides an independent assessment of the EGSl's

     response to Hurricane Rita. Based on his experience and after-action review of

     the Company's response to the storm, Mr. Davies concludes that EGSI, among

     other things: brought in the appropriate number of off-system line and vegetation

     crews; responded to Hurricane Rita consistent with generally-accepted utility

     restoration practices; had consistently expended more than most of the

     comparable utilities in maintaining its transmission and distribution infrastructure,

     meaning that the resulting damage was caused by the storm, and not by

     inadequate prior maintenance practices.

 •   At the field level, the cost witnesses prove that the Hurricane Rita costs were

     reasonable and necessary because the Company anticipated and planned for




                                           11



Hurr Recon Costs                                                                             1-015

                                          15
    the storm, organized and managed the reconstruction activities admirably under

    the circumstances, and did so quickly and safely.

•   Invoices for reconstruction services and materials were reviewed, verified, and, if

    verified to be correct, approved for payment by EGSI personnel familiar with the

    work subject to the invoices.       Invoices and charges were also reviewed and

    audited by internal accounting personnel for accuracy.            Company witnesses

    Bunting and Herman, in particular, describe the internal and external audits of the

    Hurricane Rita costs to ensure accuracy of costs and the accounting system.

•   Mr. Bunting also primarily describes the Company's internal accounting system

    and the process through which Hurricane Rita reconstruction costs were received

    and recorded into the Company's accounting system.              His testimony, in part,

    verifies the accuracy and control of the accounting system to properly record the

    Hurricane Rita reconstruction costs.

•   The affiliate cost portion of this case is a fraction of the total cost: less than 3% of

    the Total Company cost. The cost witnesses explain why theses affiliate costs,

    as distinct from the costs incurred directly by EGSI (the "non-affiliate" costs) meet

    the first two of four prongs of the affiliate cost recovery test: that is, the costs are

    (1) reasonable and (2) necessary. Company witness Bunting then explains why

    these affiliate costs satisfy the third and fourth prongs of that test: that the affiliate

    charges are (3) "not higher than" the charges by the affiliate to others; and (4) the

    affiliate charges "reasonably approximate the actual cost" of the affiliate's

    service.




                                            12



Hurr Recon Costs                                                                                 1-016

                                            16
•   Company witnesses Fetter and Hurstell address financial issues that resulted

    from, or that can result from, a storm such as Hurricane Rita.             Mr. Fetter

    addresses the financial credit ratings that apply to and affect EGSI, and how

    adverse ratings can affect a utility's cost of capital to the detriment of customers.

    He testifies as to the importance of the prompt and full recovery of reasonable

    and necessary costs incurred as a result of Hurricane Rita. He also explains why

    it is appropriate for EGSI to recover the time value of its Hurricane Rita

    expenditures.     On a related point, Mr. Hurstell describes the financial stress that

    Hurricane Rita placed on EGSI, particularly the difficulties in procuring fuel and

    purchased power from suppliers concerned over EGSl's financial health resulting

    from the storm.

•   Company witnesses Wright, Talkington, and Peters address the "rates" aspects

    of this filing.   They explain how the Total Company costs are assigned or

    allocated from $561 million down to the $393.2 million Texas retail level; and how

    the resulting costs should be functionalized and then allocated among the Texas

    retail customer classes and schedules.

•   Mr. Wright also specifically addresses the carrying charges that should be

    applied to the hurricane reconstruction costs.        He explains that the carrying

    charge rate should be the Company's weighted average cost of capital from the

    date on which the cost was incurred until the date hurricane reconstruction bonds

    are issued pursuant to a financing order to be issued in a future docket.




                                           13




Hurr Recon Costs                                                                             1-017


                                           17
                        D.     Conclusion to Executive Summary

        The Commission's decision in this case concerning EGSl's reasonable and

necessary costs associated with Hurricane Rita will define for the future the level of

urgency a utility should employ in restoring service after a major weather event. The

Commission should strive to create an incentive for Texas utilities to follow EGSl's

example in taking all actions reasonably available to restore service as quickly as

pos~ible for the benefit of customers and the regional economy.


    1

        II.      BUSINESS ADDRESS AND AUTHORIZED REPRESENTATIVES

        The business address of the Company is:

                Entergy Gulf States, Inc.
                350 Pine Street
                Beaumont, Texas 77701.

    , The business mailing address of the Company is:

                Entergy Gulf States, Inc.
                P.O. Box 2951
                Beaumont, Texas 77704.

        The business telephone number of the Company is (409) 838-6631.




                                            14




  H~rr        Recon Costs                                                                1-018

                                            18
      The authorized representatives of the Company in this proceeding are:

             Jack Blakley
             Vice President, Regulatory Affairs
             Entergy Gulf States, Inc.
             Suite 840
             919 Congress Ave.
             Austin, Texas 78701
             512-487-3975
             (Fax) 512-487-3998

             L. Richard Westerburg, Jr.
             Assistant General Counsel
             Entergy Services, Inc.
             Suite 701
             919 Congress Ave.
             Austin, Texas 78701
             512-487-3957
             (Fax) 512-487-3958

       Inquiries and pleadings concerning this Application should be directed to the

following representative:

             L. Richard Westerburg, Jr.
             Assistant General Counsel
             Entergy Services, Inc.
             Suite 701
             919 Congress Ave.
             Austin, Texas 78701
             512-487-3957
             (Fax) 512-487-3958


                   Ill.     JURISDICTION AND AFFECTED PARTIES

       The Commission has jurisdiction over EGSI and the subject matter of this

Application by virtue of Section 32.001 of the Public Utility Regulatory Act (PURA) and

House Bill 163, codified into PURA primarily at §§ 39.458 - .463. A copy of House Bill

163 is included as Attachment A to this Application.




                                           15




  Hurr Recon Costs                                                                        1-019

                                           19
       The parties, classes of customers, and territories that would be affected by

approval of this Application are all customers who currently take or will take retail

electric service from EGSI in EGSl's Texas service territory.


                                       IV.     NOTICE

       House Bill 163, PURA§ 39.462(e), explicitly states that "a rate proceeding under

Chapter 36 is not required to determine the amount of recoverable hurricane

reconstruction costs as provided by this section." Therefore, the notice requirements

specified in P.U.C. PROC. R. 22.51, which apply to Chapter 36 proceedings, do not apply

to this docket. Rather, P.U.C. PROC. R. 22.55 applies in this docket, which provides that

the Presiding Officer may require a party to provide reasonable notice to affected
                                                                                         2
persons. EGSI proposes the following with regard to public notice of this matter:

       1.     the Company proposes to publish notice of this application by one-time

              publication in newspapers having general circulation in each county of the

              Company's Texas retail service area beginning as soon as practicable

              after filing this Application;

       2.     the Company will serve a copy of this filing on all active parties who

              intervened in the Company's last general base rate filing before the

              Commission: Docket No. 30123, Application of Entergy Gulf States, Inc.

              for Authority to Change Rates and Reconcile Fuel Costs; and

       3.     the form of the notice to be provided is included as Attachment B to this

              Application. The Company requests that the Commission find that the

              Company's proposed notice is sufficient.

   2
    This proposed form of notice is the same type of notice and form approved in Docket No. 31544,
   Application of Entergy Gulf States, Inc. for Recovery of Transition to Competition Costs.

                                               16



  Hurr Recon Costs                                                                                   1-020


                                               20
            V.      CONFIDENTIAL INFORMATION AND PROTECTIVE ORDER

       Certain information that may be provided through the course of this proceeding

may contain confidential or highly-sensitive information. To facilitate evaluation of this

information by the Commission Staff and other parties in this proceeding, the Company

has prepared a Protective Order that is included as Attachment C.                  The proposed

Protective Order duplicates the protective order approved in the Company's currently

pending fuel reconciliation proceeding, Docket No. 32710. 3             EGSI requests that the

Protective Order be adopted for use in this proceeding.


            VI.     CONCLUSION TO APPLICATION AND RELIEF REQUESTED

       Through this Application, Entergy Gulf States, Inc. respectfully requests that the

Commission:

       1.         hear this case directly;

       2.         declare that notice of this filing is sufficient and authorized as provided in

                  Section IV above;

       3.         adopt the Protective Order provided in Attachment C for use in this docket;

       4.         within 150 days of this filing:

                  a) find the Company's Texas retail-jurisdictional hurricane reconstruction

                  costs of $393,236,384, through March 31, 2006, to be reasonable and

                  necessary and issue an order determining that amount of hurricane

                  reconstruction costs eligible for recovery and securitization;

                  b) authorize the Company to recover, in the financing proceeding to be

                  filed subsequent to this docket, carrying costs on the approved hurricane

   3
    Application of Entergy Gulf States, Inc. for the Authority to Reconcile Fuel and Purchased Power
   Costs (filed May 15, 2006).

                                                    17



  Hurr Recon Costs                                                                                     1-021

                                                    21
        reconstruction costs at the Company's weighted average cost of capital

        from the date on which the cost was incurred until the date transition

        bonds are issued pursuant to a financing order issued in the financing

        proceeding; and

        c) approve the manner in which hurricane reconstruction costs will be

        functionalized and the associated revenue requirement allocated in the

        future financing proceeding, as discussed in the testimonies of Company

        witnesses Wright, Talkington, and Peters attached to this Application; and

   5.   grant such other relief to which EGSI shows itself entitled.




                                      18



Hurr Recon Costs                                                                     1-022


                                      22
            - - - - - - - - - - - - - - - - - - - - - - -




                                         Respectfully submitted,

                                         L. Richard Westerburg, Jr.
                                         Steven H. Neinast
                                         ENTERGY SERVICES, INC.
                                         919 Congress Ave.
                                         Suite 701
                                         Austin, Texas 78701
                                         (512) 487-3957 telephone
                                         (512) 487~ 958 facsimil


                                  By:                           ;
                                         L. Richard We rburg, Jr.
                                         State Bar No. 21216950

                                         Mark Strain
                                         Scott Olson
                                         Clark, Thomas & Winters
                                         A Professional Corporation
                                         300 West 5th Street, 151h Floor
                                         Austin, Texas 78701
                                         (512) 472-8800
                                         (512) 474-1129 (Fax)

                                         Stephen Fogel
                                         5806 Sierra Madre
                                         Austin, Texas 78759-3924
                                         (512) 487-3946
                                         (512) 996-0983 (Fax)

                                         ATTORNEYS FOR
                                         ENTERGY GULF STATES, INC.




                              CERTIFICATE OF SERVICE

       I certify that a copy of this document was served on all active parties of record in

Docket No. 30123 on July 5, 2006, by hand-delivery, first class            ii, or overnight

delivery.




                                            19




  Hurr Recon Costs                                                                            1-023


                                            23
                                           DOCKET NO. 32907

APPLICATION OF ENTERGY GULF                             §     PUBLIC UTILITY COM~S~~ON
                                                                                               ~. '   ~· ;:")
STATES, INC. FOR DETERMINATION                          §                                     ~";
                                                                                                            \


                                                                                                                            ..-·"-
OF HURRICANE RECONSTRUCTION                             §                   OF TEXAS                        /
                                                                                                                                 '
COSTS                                                   §                                                                   \.




                                                                                                           , .          0
                                                  ORDER                                                         0       ~
                                                                                                                '-:~,
        This Order approves the application of Entergy Gulf States, Inc. (EGSI) as modif'red
through an unopposed Settlement Agreement (Agreement) filed in this docket on
November 17, 2006. EGSI, the Public Utility Commission of Texas's Staff (Commission Staff),
the Cities of Beaumont, Conroe, Groves, Pine Forest, Nederland, Port Neches, Rose City and
Silsbee (collectively, Cities), the City of Port Arthur (Port Arthur), the Office of Public Utility
Counsel (OPC), Texas Industrial Energy Consumers (TIEC), and the State of Texas (State)
(collectively, Signatories) support the Agreement and request that the Public Utility Commission
of Texas (Commission) approve the Agreement without modification.                          The East Texas
Cooperatives (ETC) 1 state that they neither oppose nor support the Agreement and that they do
not request an evidentiary hearing in this docket. This docket was processed in accordance with
applicable statutes and Commission rules. EGSI' s application, consistent with the Agreement, is
approved.


          The Commission adopts the following findings of fact and conclusions of law:


                                             I. Findings of Fact

Procedural History
1.        On July 5, 2006, EGSI filed an application, under §§ 39.458-.463 of the Public Utility
          Regulatory Act, 2 for: (1) a determination that the Hurricane Rita reconstruction costs in
          the amount of $393,236,384, incurred through March 31, 2006, are eligible for recovery
          and securitization; (2) authority to recover carrying costs at EGSI' s weighted average


          1
         .East Texas Electric Cooperative, Inc., Tex-La Electric Cooperative   of Texas, Inc., and Sam Rayburn
G&T Electric Cooperative, Inc., collectively the East Texas Cooperatives.
          2
              Public Utility Regulatory Act, TEX. UTIL. CODE ANN. §§ 11.001-66.017 (Vernon 1998 & Supp. 2006)
(PURA).




                                                                                                                                     \
DOCKET NO. 32907                             ORDER                                        PAGE2of10


      cost of capital on those hurricane reconstruction costs from the date the costs were
      incurred through the date that transition bonds are issued under a financing order issued
      in a future docket in which EGSI requests a financing order (financing order proceeding);
      and (3) approval of the manner in which the hurricane reconstruction costs will be
      functionalized and the associated revenue requirement allocated in the financing order
      proceeding.


2.    EGSI's application, filed on July 5, 2006, included the prefiled direct testimony, exhibits,
      and workpapers of eleven witnesses in support of EGSI' s request.


3.    EGSI's witnesses, as a whole, provide testimony that EGSI contends supports EGSI's
      requests.


4.    On July 7, 2006, the Commission issued Order No. 1, which provided for a protective
      order applicable to this docket and required comment on the proposed notice.


5.    On July 28, 2006, the Commission issued Order Requesting List of Issues, which
      requested that parties file lists of issues that may be addressed in this docket.


6.    On July 31, 2006, the Commission issued Order No. 6, which, among other things,
      established a procedural schedule applicable to this docket, including dates for parties to
      file testimony, discovery deadlines, and a November 1, 2006 commencement date for the
      Open Meeting hearing on the merits.


7.    The intervention deadline established for this docket was August 31, 2006.


8.    On or before August 31, 2006, the following parties filed unopposed motions to
      intervene, and their motions were granted by the Commission: OPC; Cities; TIEC; State;
      ETC; and Port Arthur.


9.    On September 1, 2006, EGSI filed its proof of notice.
DOCKET NO. 32907                            ORDER                                    PAGE3of10




10.   On September 8, 2006, the Commission issued its Preliminary Order in this docket.


11.   Discovery on EGSI's direct case concluded on September 19, 2006.


12.   On October 9, 2006, all intervenors, except ETC, filed testimony and supporting
      documents addressing EGSI's application and direct testimony, and State and Port Arthur
      also filed statements of position.


13.   All intervenors that filed testimony recommended various adjustments to the Hurricane
      Rita reconstruction costs and proposed carrying costs, or to the proposed
      functionalization and allocation, requested by EOSI.


14.   On October 12, 2006, State and TIEC filed cross-rebuttal testimony.


15.   On October 16, 2006, Commission Staff filed its testimony and a statement of position,
      which, among other things, recommended a lower carrying cost rate than EGSI had
      requested.


16.   On October 17, 2006, the Commission issued Order No. 9, which, among other things,
      directed parties not prefiling direct testimony but wishing to participate in the hearing on
      the merits to file a statement of position no later than October 24, 2006.


17.   On October 23, 2006, EGSI filed rebuttal testimony and a statement of position.


18.   On October 27, 2006, the Commission issued Order No. 12, which ruled on EGSI's
      objections and motion to strike various portions of the pre-filed testimony and supporting
      documents filed by the intervenors.


19.   At a prehearing conference convened on October 30, 2006, the Commission admitted into
      evidence: (a) all of the parties' pre-filed testimony and supporting documents, except as




                                                                                                     3
DOCKET NO. 32907                           ORDER                                    PAGE4of10


      modified or stuck by Order No. 12 and the parties' errata to their pre-filed evidence; (b)
      the parties' cross-examination exhibits; and (c) the parties' optional completeness
      exhibits. The Commission took under advisement the admissibility of several proffered
      exhibits pending its review of motions filed in response to Order No. 12. In addition,
      under Order No. 9, the parties were to convene on November 1, 2006, before the start of
      the hearing on the merits, for a continuation of the prehearing conference to address any
      remaining exhibit items.


20.   On October 30, 2006, after the prehearing conference was concluded, the Commission
      issued Order No. 13, which ruled on State's and EGSl's motions filed in response to
      Order No. 12, clarified which portions of pre-filed testimony and supporting documents
      were modified or struck by Order No. 12, and admitted additional cross-examination
      exhibits.


21.   On November 1, 2006, at the prehearing conference convened before the start of the
      hearing on the merits, the parties present requested a delay in the start of the hearing on
      the merits to enable them to continue settlement talks. The Commission granted the
      request.


22.   Later in the morning of November 1, 2006, the parties present announced that they had
      reached a settlement on all issues, stated that there was no need to conduct a hearing on
      the merits, and requested the opportunity to prepare a settlement agreement to file with
      the Commission. The Commission granted the request.


23.   On November 17, 2006, EGSI filed the Agreement, which resolves all issues in this
      docket, on behalf of itself, Commission Staff, and all active parties. The filing stated on
      behalf of ETC that ETC neither supports nor objects to the Agreement.

The Agreement
24.   Under the Agreement, the amount of EGSI' s reasonable and necessary hurricane
      reconstruction costs incurred through March 31, 2006, that is eligible for recovery and
DOCKET NO. 32907                                    ORDER                                          PAGE5of10


        securitization is $381,236,384 plus carrying costs, as set forth in findings of fact 26
        through 35.


25.     The Agreement does not reflect or determine resolution of any hurricane reconstruction
        costs that were charged to EGSI's books after March 31, 2006.


26.     In addition to $381,236,384, the Agreement authorizes EGSI to include in hurricane
        reconstruction costs and to securitize carrying costs at the rate of 7.9% per annum as
        reflected in Attachment A to this Order,3 from the later of October 15, 2005 or the date
        incurred until the issuance of securitization bonds. The balance upon which carrying
        costs are determined will be reduced by the amount of insurance payments when received
        as provided in findings of fact 27 through 30. 4


27.     The Agreement directs EGSI to credit $65. 7 million in the manner described in finding of
        fact 35, reflecting EGSI' s expectation that it will receive insurance payments in that
        amount attributable to Texas Retail.


28.     Under the Agreement, carrying costs at the rate referenced in finding of fact 26 shall
        apply to: (1) any portion of the $65.7 million referenced in finding of fact 27 not actually
        received by EGSI, until EGSI actually receives such payments attributable to Texas
        Retail; and (2) the trued-up amount, as provided in finding of fact 29, until such trued-up
        amount (plus associated carrying costs at the rate of 7.9% per annum) is recovered in
        base rates.


29.     The Agreement provides that after EGSI receives all insurance payments related to
        Humcane Rita, the $65.7 million credited, as provided in finding of fact 27, shall be
        trued up to reflect the difference between the $65.7 million credited and all insurance


        3
            Attachment Ais a copy of Exhibit A to the Agreement.
        4
            The insurance carriers include Oil Insurance Limited, Lloyd's and Hartford Steam Boiler Inspection and
Insurance Company. EGSI expects to receive $65.7·million for the Texas retail allocation (Texas Retail) out of the
total insurance payments. The total insurance payments would include amounts allocated to EGSI Louisiana as well
as EGSI Texas.




                                                                                                                     5
DOCKET NO. 32907                               ORDER                                    PAGE6of10


      payments actually received by EGSI related to Hurricane Rita attributable to Texas
      Retail.


30.   Under the Agreement, in the event EGSI receives insurance payments related to
      Hurricane Rita attributable to Texas Retail in excess of $65. 7 million after the
      Commission's issuance of a financing order in the financing order proceeding, such
      payments shall be passed through to ratepayers in the form of a rider with carrying costs
      calculated on the unamortized balance of such payments at the rate of 7 .9% per annum.


31.   The Agreement directs EGSI to continue to pursue EGSI's application for proceeds from
      governmental grants.


32.   With regard to the treatment of grant proceeds distributed prior to securitization, the
      Agreement provides as follows:


      A.        Any proceeds from governmental grants distributed directly to EGSI before the
                Commission issues a financing order shall be administered in a manner consistent
                with the conditions and directions of the grant, and, if consistent with the
                conditions and directions of the grant, shall be used to reduce the amount
                securitized. For illustrative purposes with respect to the preceding sentence, a
                reduction in the securitized amount is not considered consistent with the
                conditions and directions of the grant when, based on the cost allocation provided
                in the Agreement, such a reduction in the amount securitized would result in rates
                (transition charges) that would allocate the credit or reduction associated with the
                grant proceeds among customers or customer classes in a manner inconsistent
                with the conditions and instructions of the grant.


      B.        If a reduction of the securitized amount is not consistent with the conditions and
                directions of the grant as described in finding of fact 32, item A, and the grant
                does not prescribe carrying costs on the grant proceeds (either explicitly or
                implicitly, e.g., by instructing that the proceeds be escrowed or treated similarly),
DOCKET NO. 32907                           ORDER                                    PAGE7 oflO ·


             EGSI will reduce the securitized amount by the amount of carrying costs on the
             grant proceeds, calculated at 7.9 % per annum from EGSI's actual receipt of grant
             proceeds until the issuance of securitization bonds.


33.   The Agreement provides that any proceeds from governmental grants distributed directly
      to EGSI after the Commission's issuance of a financing order shall be administered in a
      manner consistent with the conditions and directions of the grant, and, if consistent with
      the conditions and directions of the grant, shall be passed. through to ratepayers in the
      form of a rider with carrying costs calculated on the unamortized balance of such
      proceeds at the rate of 7.9% per annum.


34.   In regard to the receipt of governmental grant proceeds as described in findings of fact 32
      and 33, the Agreement further provides that, in any event, any reduction in rates
      associated with the receipt of governmental grant proceeds shall be no greater than the
      amount of such proceeds, subject to the calculation of carrying costs provided in findings
      of fact 32 and 33.


35.   Under the Agreement, the total dollar amount eligible to be securitized in the financing
      order proceeding (as reflected in Attachment A to this Order) shall be: $381,236,384 plus
      carrying costs at the· rate and for the time period specified in findings offact 26 through
      30, minus $65.7 million related to insurance, plus all other qualified costs, to be
      determined by the Commission in the financing order proceeding, provided for in PURA
      § 39.460(d).


36.   The Agreement provides that the present value of the benefit, if any, of accumulated
      deferred federal income taxes and method of handling such benefit will be part of EGSI's
      presentation in the financing order proceeding and subject to the Commission's
      determination about how such benefit, if any, should be treated in the financing order or a
      subsequent proceeding.




                                                                                              7
DOCKET NO. 32907                           ORDER                                     PAGESoflO


37.   Under the Agreement: (a) the functionalization and allocation methodology proposed by
      EGSI in its filed case shall be utilized in the financing order proceeding; and (b)
      adjustments described in findings of fact 24 through 36 shall be functionalized and
      allocated pro rata in the same manner as proposed by EGSI in its filed case.


38.   The Agreement includes standard provisions regarding waiver, general terms and
      conditions, lack of precedential effect, and termination of the Agreement in the event the
      Commission does not accept the Agreement as presented.


39.   The Agreement resolves all issues of fact and law applicable to this docket.


40.   Approval of the Agreement is in the public interest.


                                   II. Conclusions of Law

1.    EGSI is a public utility as that term is defined in §§ 11.004 and 31.002 of PURA.


2.    The Commission has jurisdiction over this proceeding under PURA§§ 39.458-.463.


3.    EGSI provided appropriate notice of this proceeding in accordance with P.U.C. PROC.
      R. 22.55.


4.    EGSI's application was processed in accordance with PURA §§ 39.458-.463 and the
      Administrative Procedure Act, TEX. Gov'T CODE ANN. §§ 2001.001-.902 (Vernon 2000
      & Supp. 2006).


5.    PURA §§ 39.458-.463 allow, among other things, EGSI to obtain timely recovery of
      reasonable and necessary Hurricane Rita reconstruction costs and to use securitization
      financing to recover those costs.
 DOCKET NO. 32907                            ORDER                                     PAGE 9of10


· 6.   The functionalization and allocation methodology proposed by EGSI in its filed case
       complies with PURA§ 39.460(g).


 7.    The evidentiary record, which includes testimony and exhibits filed by EGSI,
       Commission Staff, Cities, TIEC, OPC, and State, supports the Agreement.


 8.    Because the Agreement is the result of an unopposed agreement among the parties, an
       adjudicatory hearing is not required to process EGSI's application in this docket.


                                   III. Ordering Paragraphs

 1.    EGSI's request for a determination of the dollar amount of its Hurricane Rita
       reconstruction costs, incurred through March 31, 2006, plus carrying costs, that are
       eligible for recovery and securitization in the financing order proceeding, as described in
       finding of fact 35 and the Agreement, is approved.


 2.    In the financing order proceeding, the hurricane reconstruction costs shall be
       functionalized and the associated revenue requirement allocated in the manner proposed
       by EGSI in its case filed on July 5, 2006.


 3.    EGSI shall comply with the true-up provisions regarding insurance payments as set out in
       findings of fact 28 through 30.


 4.    EGSI shall treat governmental grant proceeds in the manner set out in findings of fact 32
       through 34.


 5.    EGSI shall continue to pursue its application for proceeds from governmental grants.


 6.    EGSI shall file, semi-annually from the date of this order, in Project No. 33560,
       Compliance Report of Entergy Gulf States, Inc. in Response to Final Order in Docket No.
       32907, a report detailing all alternative sources of recovery of its hurricane reconstruction
       costs, including but not limited to insurance and grants.
DOCKET NO. 32907                              ORDER                                  PAGE lOoflO




7.       Entry of this Order does not indicate the Commission's endorsement or approval of any
         principle or methodology that may underlie the Agreement. Neither shall the entry of the
         Order be regarded as binding precedent as to the appropriateness of any principle
         underlying the Agreement.


8.       All other motions, requests for entry of specific findings of fact and conclusions of law,
         and any other request for general or specific relief, if not expressly granted herein, are
         denied.

         SIGNED AT AUSTIN, TEXAS the               \ G\-   day of December 2006.


                                              PUBLIC UTILITY COMMISSION OF TEXAS




q:\cadm\orders\final\32000\32907 fo.doc
                                                                                                                                            Attachment A




Entergy Gulf StatM, Inc.                                                                                                                 Docket No. 32907
Rita Stonn R"toratlon CoaU for TX                                                                                                    Settlement Agreement
btlmate Of Carrying C09t for TX Reta•                                                                                                            Exhibit A
For C09ta Incurred September 2001 - March 2oot                                                                                                  Paga 1of1
(Amount. In Doller.)



TX Retail Carrying Colt

  Beginning                                                Adjusted Colt
   Month of         TXRetaA           Accrual                Including                              Balance for          Settlement
 Carrying Coet       Colt            Adjustment             Settlement        Canylng Coet         Carrying Coata       Adjuatmanta
    Sep05            1,552,688                                   1,504,592                               1,504,592            (48,093)
     Oct05          66,174,848              (475,471)          63,649,651             219,419           65,373,662        (2,049,724)
    Nov05           82,799,332               147,669            80,382,344            694,961          146,450,974        (2,584,657)
    Dec05           58,588,197              (361,211)           56,421,944          1,149,858          204,022,778        (1,815,042)
     Jan 08         34,649,048               626,801            34,202,617          1,455,734          239,681,128        (1,073,232)
     Feb OS         55,318,008              (134,812)           53,469,755          1,753,905          294,904,788        (1,713,440)
    Maroa           88,324,964           (35,544,631)           50,044,523          2,106,186          347 ,055,496       (2,735,810)
    Apr-08                                25,086,733            25,086,733          2,367,359          374,509,588
    May-o&                                10,654,922            10,654,922          2,500,594          387,665,104
     Jun-08                                                                         2,552,1211         390,217,232
     Jul-08                                                                         2,568,930          392, 786, 182
     Aug-06                                                                         2,585,842          383,228,245                             (12, 143,780)
     Sep-08                                                                         2,522,919          385,751, 184
     Oct-08                                                                         2,539,528          388,290,892
     Nov-06                                                                         2,556,247 .        390,846,940
     Dec-Oii                                                                        2,573,076          393,420,015
    Jan-07                                                                          2,590,015          396,010,030
    Feb-07                                                                          2,607,066          398,617,098
    Mar-07                                                                          2,624,229          401,241,329
    Apr-07                                                                          2,641,505          403,882,831
    May-o7                                                                          2,658,8915         406,541,728
Sub-Tofall         387,417,080                                375,417,080          43,268,406                                (12,000,000)      (12, 143,780)

leaaAFUDC
 Sep 05 - Mar 06                                                                    (5.819,304)

Total Carrying Coata                                                                37,449,102

Sum1111ry
TX Re1al Costa N1ove                                           371,417 ,080
AFUOC                                                            5,819,3fM
Total TX Retal Coats Per Exh JOW-2 leaa Seti. Adj.             381,236,314

Total Canying Coa1a                                             37,449,102

Total to Recover Alsuming a June 1 Securitlzallon              418,685,481
(Carrying coala to be calculated untll lnuance of bonds)

Ina. to Remove for Securitlzalion (TX Re1al'Amt.)               85,700,000

 Total to Securitiza Anuming a June 1 Securitization           3152,986,481


 Notes:
TX Retall Coat excludes AFUOC.
Accruals Adjustment subtracts coala that are accrued but not yet paid. Accruals are assumed to be paid In lul by May 2006.
Carrying Coat • (Current Month Adjusted Coat • 112 Month + Prier Month Balance to Recover) • Carrying Cost
Hurricane Rita tax benefits have not been re11llzad as the Company ls In a net operating toss carryforward position.
Amounts may not aum to totals due to rounding.
Plus al other qualliad coats provided for in Section 39.480(d) of PURA.

 Carrying Coat                                                                            7.911%




                                                                          /7                                                                           Page 10 of 10
•
·~·Entergy
                                                                                     Entergy Services, Inc.
                                                                                     Legal Services
                                                                                     919 Congress Avenue
                                                                                     Suite 701
                                                                                     Austin, TX 78701


                                                           f :•.:'/   17 f';J}. !!~rd Westerburg, Jr.
                                                                          Assis~1 General Counsel
                                                    PUt!Lf;; :. r             :siop1 512-487-3944
                                                             I i~;i;., CUL ,         512-487-3958




                                     November 17, 2006

    Judge Andrew Kang
    Administrative Law Judge
    Public Utility Commission of Texas
    1701 North Congress Avenue
    Austin, Texas 78711

    Re:    P.U.C. Docket No. 32907,Application of Entergy Gulf States, Inc.for
           Determination ofHurricane Reconstruction Costs

    Dear Judge Kang:

    Pursuant to Order No. 15, please find attached the Settlement Agreement and Proposed
    Order in Docket No. 32907 for consideration and decision at the Commission's
    December 1, 2006 Open Meeting. Also, pursuant to Order No. 1, the statutory deadline
    for the issuance of an order is December 2, 2006. Accordingly, Entergy Gulf States, Inc.
    requests the Order be signed by the Commission on December 1, 2006.

    As reflected in the Settlement Agreement, the East Texas Cooperatives (ETC) (East
    Texas Electric Cooperative, Inc., Sam Rayburn G&T Electric Cooperative, Inc., and Tex-
    La Electric Cooperative of Texas, Inc.), who are intervenors in this docket, have
    authorized the Signatories to represent that ETC neither supports nor opposes this
    Agreement and that ETC does not request an evidentiary hearing in this docket.

    Sincerely,//              r             )
      1 lt~h-#'}:dt'~-
    L. Richard Westerburg, Jr.

    cc:    PUC Filing Clerk
           All Parties
                                   DOCKET NO. 32907

 APPLICATION OF ENTERGY GULF                    §              BEFORE THE
 STATES, INC. FOR                               §       PUBLIC UTILITY COMMISSION
 DETERMINATION OF HURRICANE                     §               OF TEXAS
 RECONSTRUCTION COSTS                           §

                                  SETTLEMENT AGREEMENT

1.     Preamble.

        1.1.   This Settlement Agreement (Agreement) is entered in this docket

before the Public Utility Commission of Texas (Commission) by and among:

Entergy Gulf States, Inc. (EGSI or Company); the Staff of the Public Utility

Commission. of Texas (Staff); the Cities of Beaumont, Conroe, Groves, Pine

Forest, Nederland, Port Neches, Rose City and Silsbee (collectively, Cities); the

City of Port Arthur (Port Arthur); the Office of Public Utility Counsel (OPC); Texas

Industrial Energy Consumers {TIEC); and the State of Texas {State) (collectively,

Signatories ). 1

        1.2.   On July 5, 2006, EGSI filed an application in Commission Docket

No. 32907, under House Bill 163, for: (1) a determination that the Hurricane Rita

reconstruction costs in the amount of $393,236,384 (Texas retail jurisdictional

amount), incurred by EGSI through March 31, 2006, are eligible for recovery and

securitization; (2) authority to recover carrying costs at the Company's weighted

average cost of capital on those hurricane reconstruction costs from the date the

costs were incurred through the date that transition bonds are issued under a


       1
          The only other parties in the case-the East Texas Cooperatives (ETC} (East Texas
Electric Cooperative, Inc., Sam Rayburn G&T Electric Cooperative, Inc. and Tex-La Electric
Cooperative of Texas, lnc.)-authorize the Signatories to represent that ETC neither supports nor
opposes this Agreement and that ETC does not request an evidentiary hearing in this docket.

                                                                            Docket No. 32907
                                                                       Settlement Agreement
                                                                                  Page 1of10
financing order issued in a future docket in which the Company requests a

financing order (financing order proceeding); and (3) approval of the manner in

which the hurricane reconstruction costs will be functionalized and the associated

revenue requirement allocated in the financing order proceeding.               The

Signatories filed direct and rebuttal testimony, and statements of position, stating

their respective positions in this docket. The Signatories agree to the following

terms in settlement of issues arising in this docket.

2.     Reasonable and Necessary Hurricane Reconstruction Costs.

       The amount of the Company's reasonable and necessary hurricane

reconstruction costs determined, in this docket, to be eligible for recovery and

securitization is $381,236,384 plus carrying costs, as set forth in paragraph nos.

3 through 6 of this Agreement. This Agreement does not reflect or determine

resolution of any hurricane reconstruction costs that were charged to the

Company's books after March 31, 2006.

3.     Carrying Costs.

       In addition to $381,236,384, the Company is authorized to include in

hurricane reconstruction costs and securitize carrying costs at the rate of 7 .9%

per annum, as reflected in Exhibit A attached to this Agreement, from the later of

October 15, 2005 or the date incurred until the issuance of securitization bonds.

The balance upon which carrying costs are determined will be reduced by the

amount of insurance payments when received, as provided in paragraph no. 4 to

this Agreement.




                                                                    Docket No. 32907
                                                               Settlement Agreement
                                                                        Page 2of10
4.    Insurance Proceeds.

      The Company shall credit $65. 7 million in the manner described in

paragraph no. 6 to this Agreement, reflecting the Company's expectation that it

will receive insurance payments in that amount (Texas Retail). Carrying costs at

the rate referenced in paragraph no. 3 shall apply to: (1) any portion of the $65.7

million not actually received by the Company, until the Company actually

receives (Texas Retail) such payments; and (2) the trued-up amount, as provided

below, until such trued-up amount (plus associated carrying costs at the rate of

7.9% per annum) is recovered in base rates. Subsequent to the receipt of all

insurance payments related to Hurricane Rita, the $65.7 million credited, as

provided in this paragraph, shall be trued up to reflect the difference between the

$65.7 million credited and all insurance payments actually received by the

Company related to Hurricane Rita for Texas Retail. In the event the Company

receives insurance payments related to Hurricane Rita for Texas Retail in excess

of $65.7 million after the Commission's issuance of a financing order in the

financing order proceeding, such payments shall be passed through to

ratepayers in the form of a rider with carrying costs calculated on the

unamortized balance of such payments at the rate of 7.9% per annum.




                                                                   Docket No. 32907
                                                              Settlement Agreement
                                                                       Page 3of10
5.     Proceeds from Governmental Grants.

       A.       Pursuit of Governmental Grants.

       5.1      The Company shall continue to pursue its application for proceeds

from governmental grants.

       B.       Treatment of grant proceeds distributed prior to securitization.

       5.2      Any proceeds distributed directly to the Company prior to the

Commission's issuance of a financing order shall be administered in a manner

consistent with the conditions and directions of the grant, and, if consistent with

the conditions and directions of the grant, shall be used to reduce the amount

secu ritized.

       5.3      For illustrative purposes with respect to paragraph no. 5.2 of this

Agreement, a reduction in the securitized amount is not considered consistent

with the conditions and directions of the grant when, based on the cost allocation

provided in this Agreement, such a reduction in the amount securitized would

result in rates (transition charges) that would allocate the credit or reduction

associated with the grant proceeds among customers or customer classes in a

manner inconsistent with the conditions and instructions of the grant.

       5.4      If a reduction of the securitized amount is not consistent with the

conditions and directions of the grant as described in the paragraph no. 5.3 of

this Agreement and the grant does not prescribe carrying costs on the grant

proceeds (either explicitly or implicitly, e.g., by instructing that the proceeds be

escrowed or treated similarly), the Company will reduce the securitized amount

by the amount of carrying costs on the grant proceeds, calculated at 7 .9% per


                                                                   Docket No. 32907
                                                              Settlement Agreement
                                                                       Page 4of10
                                    s
annum from the Company's actual receipt of grant proceeds until the issuance of

securitization bonds.

      C.     Treatment of grant proceeds distributed after securitization.

      5.5    Any proceeds distributed directly to the Company after the

Commission's issuance of a financing order shall be administered in a manner

consistent with the conditions and directions of the grant, and, if consistent with

the conditions and directions of the grant, shall be passed through to ratepayers

in the form of a rider with carrying costs calculated on the unamortized balance of

such proceeds at the rate of 7 .9% per annum.

       D.     Reduction in rates due to grant proceeds.

       5.6    In any event, any reduction in rates associated with the receipt of

grant proceeds, whether before or after securitization, shall be no greater than

the amount of such proceeds, subject to the calculation of carrying costs

provided in paragraph nos. 5.4 and 5.5 of this Agreement.

6.     Amount to be Securitized.

       The total amount eligible to be securitized in the financing order

proceeding (as reflected in Exhibit A attached to this Agreement) shall be:

$381,236,384 plus carrying costs at the rate and for the time period specified in

paragraph no. 3, minus $65. 7 million related to insurance, plus all other qualified

costs, to be determined by the Commission in the financing order proceeding, as

provided for in Section 39.460(d) of the Public Utility Regulatory Act, TEX. UTIL.

CODE Title 2. The present value of the benefit, if any, of accumulated deferred

federal income taxes and method of handling such benefit will be part of the


                                                                    Docket No. 32907
                                                               Settlement Agreement

                                    b                                   Page 5of10
Company's presentation in the financing order proceeding and subject to the

Commission's determination about how such benefit, if any, should be treated in

the financing order or a subsequent proceeding.

7.     Functionalization and Allocation.

       The parties agree that the functionalization and allocation methodology

proposed by EGSI in its filed case shall be utilized in the financing order

proceeding.      Adjustments described in the preceding paragraphs shall be

functionalized and allocated pro rata in the same manner as proposed by EGSI

in its filed case.

8.      No Waiver.

        Except as to matters determined in this Agreement, no Signatory, by

entering into the Agreement, waives its right to take any position in any

proceeding as to any issue(s) related to the Hurricane Rita reconstruction costs

that may arise in any other docket, appeal, or any other matter. Each Signatory

specifically reserves, and does not waive, its individual right to file any pleading,

or to participate in, or to initiate any proceeding to assert or support such

position, or to engage in any combination of these activities, except a pleading

that is inconsistent with the settlement points described in this Agreement.




                                                                    Docket No. 32907
                                                               Settlement Agreement
                                                                        Page 6of10
                                    7
9.    Other Terms and Conditions.

      After extensive negotiations, the Signatories have reached a compromise

and settlement regarding each of the matters discussed in this Agreement. The

Signatories agree that this Agreement is in the public interest and urge the

Commission to adopt a final order consistent with all of its terms.    Oral and

written statements made during the course of the settlement negotiations shall

not be used as an admission or concession of any sort or as evidence in this or

any other proceeding. None of the Signatories agrees to the propriety of any

regulatory theory or principle that may be said to underlie any of the issues

resolved by this Agreement.      Because this is a stipulated agreement, the

Signatories recognized that no Signatory is under any obligation to take the same

position as set out in this Agreement in any other docket, except as specifically

required by this Agreement, whether or not that docket presents the same or

similar circumstances.

10.   No Precedent.

      Further, given that the matters resolved in this Agreement are resolved on

the basis of compromise and settlement, the Signatories agree that nothing in

this Agreement should be considered to be precedent in any other Commission

proceeding, except a proceeding to enforce the terms of this Agreement. This

Agreement reflects a compromise, settlement and accommodation among the

Signatories, and the terms and conditions of this Agreement are interdependent.

All actions by the Signatories contemplated or required by this Agreement are

conditioned upon entry by the Commission of a final and appealable order


                                                                 Docket No. 32907
                                                            Settlement Agreement
                                                                     Page 7of10
consistent with this Agreement.        If the Commission does not accept this

Agreement as presented and enters an order inconsistent with any term of this

Agreement, any Signatory shall have the right to withdraw from this Agreement,

which withdrawal shall render the Agreement null and void.            Any Signatory

electing to withdraw from this Agreement shall notify all other Signatories in

writing of such withdrawal. After the withdrawal, a new hearing will be held, if

requested, and the parties have the right to file new testimony. This Agreement

is binding on each of the Signatories only for the purpose of settling the issues

described in this Agreement and for no other purpose.

11.    Authorization to Sign.

       Each person executing this Agreement represents that (s)he is authorized

to sign this Agreement on behalf of the party represented.

12.    Countersigned Originals.

       This document may be countersigned by each party on separate originals.

Each signature shall be treated as if it is an original signature.




                                                                      Docket No. 32907
                                                                 Settlement Agreement
                                                                          Page 8of10
11/17/2006 15:40 FAX   5129367268          PUC LEGAL AND ENFORCEMEN                      ~002/003




          STAFF OF THE                                CITIES OF BEAUMONT, CONROE, GROVES,
          PUBLIC UTILITY COMMISSION OF TEXAS          NEDERLAND, PINE FOREST, PORT NECHES,
                                                      ROSE CITY, AND SILSBEE

           Date of Execution: November   11~ 2006.    Date of Execution: November __, 2006




           By~~Zttt
           0FRCE OF PUBLIC UTILITY COUNSEL            STATE OF TEXAS,
                                                      OFFICE OF THE ATTORNEY GENERAL

           Date of Execution: November       , 2006   Date of Execution: November       , 2006



           By:_ _ _ _ _ _ _ _ _ _ _ __                By: _ _ _ _ _ _ _ _ _ _ __



           CITY OF PORT ARTHUR                        TEXAS INDUSTRIAL ENERGY CONSUMERS

           Date of Execution: November __, 2006       Date of Execution: November __, 2006



           By:_ _ _ _ _ _ _ _ _ _ _ __                By: _ _ _ _ _ _ _ _ _ __



           ENTERGY GULF STATES, INC.

           Date of Execution: November __, 2006



           By:._ _ _ _ _ _ _ _ _ _ _ __




                                                                         Docket No. 32907
                                                                      Settlement Agreement
                                                                              Page 9of10
STAFF OF THE                              CITIES OF BEAUMONT, CONROE, GROVES,
PUBLIC UTILITY COMMISSION OF TEXAS        NEDERLAND, PINE FOREST, PORT NECHES,
                                          ROSE CITY, AND SILSBEE

Date of Execution: November _ _ , 2006.   Date of Execution: November _ _ , 2006



By: _ _ _ _ _ _ _ _ _ _ _ __              By: _ _ _ _ _ _ _ _ _ _ _ __



OFFICE OF PUBLIC UTILITY COUNSEL          STATE OF TEXAS,
                                          OFFICE OF THE ATTORNEY GENERAL

Date of Execution: November   JZ. 2006    Date of Execution: November __ , 2006



By:'l&f~                                  By: _ _ _ _ _ _ _ _ _ _ _ _ __



CITY OF PORT ARTHUR                       TEXAS INDUSTRIAL ENERGY CONSUMERS

Date of Execution: November _ _ , 2006    Date of Execution: November _ _ , 2006




By: _ _ _ _ _ _ _ _ _ _ _ _ __            By: _ _ _ _ _ _ _ _ _ _ _ _ __



ENTERGY GULF STATES, INC.

Date of Execution: November _ _ , 2006




By: _ _ _ _ _ _ _ _ _ _ _ _ __




                                                             Docket No. 32907
                                                        Settlement Agreement
                                                                 Page 9of10
                                   I(
NOV-17-2006 FRI 09:43 AM                                FAX NO.                           P. 03




        sTAFF OF nm:                                  CITIES OF BEAUMONT, CONROE, GROVES,
                                                      NEDERLAND, PINE fOREST, PORT NECHES,
        PUBLIC UTILITY COMMlSSION OF TEXAS
                                                      ROSf:: CliY, AND SILSSEE

        Date of Execution: November~-· 2006.          Date of Execution: November_, 2006



         By:________._ _ _ _ __                       By; ______________



         OFFICE OF PUBLIC UTILITY COUNSEL             STATE OF TEXAS,
                                                      OFFICE OF THE ATTORNEY GENERAL


         Date of Execution: November_, 2006           Date of Execution: November_. 2006


                                                       By: _ _ _ _ _ _ _ _ _ _           ~



         By:_ _ _~


         Cl'TY OF PORT ARTHUR                          TEXAS INDUSTRIAL ENERGV CONSUMERS


         Date of Execution: November J!]_, 2006        Date of Execution: November
                                                                                     -   , 2006




          By:~                     ....;;.••: ... ,;.... B y : _ N_ _


          ENTERGY GULF STATES, INC.

          Date of Execution: November        , 2006




          By: ___   w·---------


                                                                           Docket No. 32907
                                                                      Settlement Agreement
                                                                               Page 9of10
STAFF OF THE                              CITIES OF BEAUMONT, CONROE, GROVES,
PUBLIC UTILITY COMMISSION OF TEXAS        NEDERLAND, PINE FOREST, PORT NECHES,
                                          ROSE CITY, AND SILSBEE

Date of Execution: November _ _ , 2006.   Date of Execution: November   n.   2006



By: _ _ _ _ _ _ _ _ _ _ _ __              By:U{~
OFFICE OF PUBLIC UTILITY COUNSEL          STATE OF TEXAS,
                                          OFFICE OF THE ATTORNEY GENERAL

Date of Execution: November _ _ , 2006    Date of Execution: November _ _ , 2006



By: _ _ _ _ _ _ _ _ _ _ _ __              By: _ _ _ _ _ _ _ _ _ _ _ __



CITY OF PORT ARTHUR                       TEXAS INDUSTRIAL ENERGY CONSUMERS

Date of Execution: November _ _, 2006     Date of Execution: November _ _ , 2006




By: _ _ _ _ _ _ _ _ _ _ _ _ __            By: _ _ _ _ _ _ _ _ _ _ _ __



ENTERGY GULF STATES, INC.

Date of Execution: November _ _ , 2006




By: _ _ _ _ _ _ _ _ _ _ _ _ __




                                                             Docket No. 32907
                                                        Settlement Agreement
                                                                 Page 9of10
                                   13
11/14/2006   22:08   512-322-9114                PAR/ATTV.GEN.OFC.                     PAGE   02/02




      STAFF PF THE                               CITIES OF BEAUMONT, CONROE,.GROVES,
      PUBLIC UTILITY COMMISSION Of TEXAS         NEDERLAND, PINE FOREST, PORT NECHES,
                                                 ROSE CITY, AND SILSBE:E

      Date of Execution: November_, 2006.        Date of Execution: November_, 2006



      By:                                        By:._ _ _ _ _ _ _ _ _ _ __



      OFFICE OF PUBLIC UTILITY COUNSEL           STATE OF TEXAS,
                                                 OFFICE OF THE ATTORNEY GENERAL

      Date of Execution: November._, 2006        Date of Execution: November    J.1_, 2006

      By:                                        By:t.W~ffi~
                                                   ;O  }~ .
      CITY OF PORT ARTHUR                        TEXAS INDUSl'RIAL ENERGY CONSUMERS

      Date of Execution: November____.:_, 2006   Date of Execution: November_. 2006




      ENTERGY GULF'. STATES, INC.

      Date of Execution: November_. 2006



      By:_ _ _ _ _ _ _ _ _ _ _ __




                                                                        Docket No. 32907
                                                                   Settlement Agreement
                                                                            Page 9of10·


                                         If
11-17-06   09:18am   From-ANOREWSKURTH               +5123209292      T-186   P.002/002   F-418




            STAFF OF THE                             CITIES OF BEAUMONT, CONROE, GROVES,
            PUBLIC UTILITY COMMISSION OF TEXAS       NEDERLAND, PINE FOREST, PORT NECHES,
                                                     ROSE CITY, AND SILSBEE

            Date of Execution: November __ , 2006.   Date of Execution: November __ , 2006



            By:_ _ _ _ _ _ _ _ _ _ _ __              By: _ _ _ _ _ _ _ _ _ _ __



            OFFICE OF PUBLIC UTILITY COUNSEL         STATe OF TEXAS,
                                                     OFFICE OF THE ATTORNEY GeN5RAL

            Date of Execution: November __ , 2006    Date of Execution: November __ , 2006



            By:                                      By: _ _ _ _ _ _ _ _ _ _ _ __
                -------------
            CITY OF PORT ARTHUR                      TEXAS INDUSTRIAL ENERGY CONSUMERS

            Date of Execution: November __ , 2006    Date of Execution: November   I(t' , 2006


            By:-----------~-


            ENTERGY GULF STATES, INC.

            Date of Execution: November~-· 2006




            By:
                -------------



                                                                        Docket No. 32907
                                                                   Settlement Agreement
                                                                            Page 9of10
STAFF OF THE                             CITIES OF BEAUMONT, CONROE, GROVES,
PUBLIC UTILITY COMMISSION OF TEXAS       NEDERLAND, PINE FOREST, PORT NECHES,
                                         ROSE CITY, AND SILSBEE

Date of Execution: November __ , 2006.   Date of Execution: November _ _ , 2006



By:. _ _ _ _ _ _ _ _ _ _ _ __            By:. _ _ _ _ _ _ _ _ _ _ _ __



OFFICE OF PUBLIC UTILITY COUNSEL         STATE OF TEXAS,
                                         OFFICE OF THE ATTORNEY GENERAL

Date of Execution: November __ , 2006    Date of Execution: November _ _ , 2006



By: _ _ _ _ _ _ _ _ _ _ _ __             By: _ _ _ _ _ _ _ _ _ _ _ __



CITY OF PORT ARTHUR                      TEXAS INDUSTRIAL ENERGY CONSUMERS

Date of Execution: November __ , 2006    Date of Execution: November _ _ , 2006




By: _ _ _ _ _ _ _ _ _ _ _ __             By: _ _ _ _ _ _ _ _ _ _ _ __




                                                            Docket No. 32907
                                                       Settlement Agreement
                                   Ib                           Page 9of10
Entergy Gulf States, Inc.                                                                                                                 Docket No. 32907
Rita Stonn Restoration Costs for TX                                                                                                   Settlement Agreement
Estimate of Carrying Cost for TX Retail                                                                                                           Exhibit A
For Costs Incurred September 2006 - March 2006                                                                                                   Page 1of1
(Amounts in Dollars)




TX Retail Carrying Cost

  Beginning                                                 Adjusted Cost                                                                     Estimated
   Month of         TX Retail           Accrual               Including                              Balance for          Settlement          Insurance
 Carrying Cost        Cost             Adjustment            Settlement        Carrying Cost        Carrying Costs       Adjustments          Payments
    Sep OS           1,SS2,666                                    1,S04,S92                               1,504,592           (48,093)
    Oct OS          66,174,646               (47S,471)           63,649,6S1            219,419           65,373,662        (2,049,724)
    Nov OS          82,799,332                147,669            80,382,344            694,968          146,450,974        (2,564,6S7)
    Decos           S8,S98,197               (361,211)           S6,421,944          1,149,8S8          204,022,776        (1,815,042)
    Jan 06          34,649,048                626,801            34,202,617          1,455,734          239,681,126        (1,073,232)
    Feb 06          5S,318,008               (134,812)           53,469,7S5          1,7S3,90S          294,904,786        (1,713,440)
    Mar06           88,324,964            (3S,S44,631)           S0,044,S23          2,106,186          347,055,496        (2,735,810)
    Apr-06                                 25,086,733            25,066,733          2,367,359          374,509,588
    May-06                                 10,6S4,922            10,654,922          2,500,594          367 ,665, 104
    Jun-06                                                                           2,5S2,129          390,217 ,232
     Jul-06                                                                          2,568,930          392,786,162
    Aug-06                                                                           2,585,842          383,228,245                             (12, 143,760)
    Sep-06                                                                           2,S22,919          365,751,164
    Oct-06                                                                           2,539,528          388,290,692
    Nov-06                                                                           2,556,247          390,846,940
    Dec-06                                                                           2,S73,076          393,420,015
    Jan-07                                                                           2,590,015          396,010,030
    Feb-07                                                                           2,607,066          398,617,096
    Mar-07                                                                           2,624,229          401,241,326
    Apr-07                                                                           2,641,505          403,882,831
    May-07                                                                           2,658,89S          406,541, 726
Sub-Totals         387,417,080                                 37S,417,080          43,268,406                                (12,000,000)      (12, 143,760)

LessAFUDC
 Sep OS - Mar 06                                                                     (5,819,304)

Total Carrying Costs                                                                 37,449,102

Summary

TX Retail Costs Above                                          375,417,080
A FU DC                                                          5,819,304
Total TX Retail Costs Per Exh JDW-2 Less Setl. Adj.            381,236,384

Total Carrying Costs                                             37,449,102

Total to Recover Assuming a June 1 Securitization              418,686,486
(Carrying costs to be calculated until issuance of bonds)

Ins. to Remove tor Securitization (TX Retail Amt.)               65,700,000

Total to Securitize Assuming a June 1 Securitization            352,985,486



Notes:
TX Retail Cost excludes AFUDC.
Accruals Adjustment subtracts costs that are accrued but not yet paid. Accruals are assumed to be paid in full by May 2006.
Carrying Cost= (Current Month Adjusted Cost* 1/2 Month + Prior Month Balance to Recover) • Carrying Cost
Hurricane Rita tax benefits have not been realized as the Company is in a net operating loss carryforward position.
Amounts may not sum to totals due to rounding.
Plus all other qualified costs provided for in Section 39.460(d) of PURA.

Carrying Cost                                                                              7.90%




                                                                          /7                                                                            Page 10 of 10
                                         PUC DOCKET NO. 32907

 APPLICATION OF ENTERGY GULF                         §      PUBLIC UTILITY COMMISSION
 STATES, INC. FOR                                    §
 DETERMINATION OF HURRICANE                          §                    OF TEXAS
 RECONSTRUCTION COSTS                                §

                                            PROPOSED ORDER

           This Order approves the application of Entergy Gulf States, Inc. (EGSI), as modified
through an unopposed Settlement Agreement (Agreement) filed in this docket on November
17, 2006. EGSI, the Public Utility Commission of Texas's Staff (Commission Staff), the Cities
of Beaumont, Conroe, Groves, Pine Forest, Nederland, Port Neches, Rose City and Silsbee
(collectively, Cities), the City of Port Arthur (Port Arthur), the Office of Public Utility Counsel
(OPC), Texas Industrial Energy Consumers (TIEC), and the State of Texas (State) (collectively,
Signatories) support the Agreement and request that the Public Utility Commission of Texas
(Commission) approve the Agreement without modification.                   The East Texas Cooperatives
       1
(ETC) state that they neither oppose nor support the Agreement and that they do not request an
evidentiary hearing in this docket. This docket was processed in accordance with applicable
statutes and Commission rules. EGSI' s application, consistent with the Agreement, is approved.


           The Commission adopts the following findings of fact and conclusions of law:


                                             I. Findings of Fact

Procedural History
1.         On July 5, 2006, EGSI filed an application, under §§ 39.458-.463 of the Public Utility
           Regulatory Act, 2 for: (1) a determination that the Hurricane Rita reconstruction costs in
           the amount of $393,236,384 (Texas retail jurisdictional amount), incurred through March
           31, 2006, are eligible for recovery and securitization; (2) authority to recover carrying
           costs at EGSI's weighted average cost of capital on those hurricane reconstruction costs
           from the date the costs were incurred through the date that transition bonds are issued
           under a financing order issued in a future docket in which EGSI requests a financing

           1
          East Texas Electric Cooperative, Inc., Tex-La Electric Cooperative of Texas, Inc., and Sam Rayburn
G&T Electric Cooperative, Inc., collectively the East Texas Cooperatives (ETC).
           2
               Public Utility Regulatory Act, TEX. UTIL. CODE ANN. §§ 11.001-66.017 (Vernon 1998 & Supp. 2006)
(PURA).
                                                      /8
PUC DOCKET NO. 32907
                                            PROPOSED ORDER                                PAGE2


      order (financing order proceeding); and (3) approval of the manner in which the
      hurricane reconstruction costs will be functionalized and the associated revenue
      requirement allocated in the financing order proceeding.


2.    EGSI's July 5, 2006 application included the prefiled direct testimony, exhibits, and
      workpapers of eleven witnesses in support of EGSI' s request.


3.    EGSI's witnesses, as a whole, provide testimony that EGSI contends supports EGSI's
      requests.


4.    On July 7, 2006, the Commission issued Order No. 1, which provided for a protective
      order applicable to this docket and required comment on the proposed notice.


5.    On July 28, 2006, the Commission issued Order Requesting List of Issues, which
      requested that parties file lists of issues that may be addressed in this docket.


6.    On July 31, 2006, the Commission issued Order No. 6, which, among other things,
      established a procedural schedule applicable to this docket, including dates for parties to
      file testimony, discovery deadlines, and a November 1, 2006 commencement date for the
      hearing on the merits.


7.    The intervention deadline established for this docket was August 31, 2006.


8.    On or before August 31, 2006, the following parties filed unopposed motions to
      intervene, and their motions were granted by the Commission: OPC; Cities; TIEC; State;
      ETC; and Port Arthur.


9.    On September 1, 2006, EGSI filed its proof of notice.


10.   On September 8, 2006, the Commission issued its Preliminary Order in this docket.


11.   Discovery on EGSI's direct case concluded on September 19, 2006.
PUC DOCKET NO. 32907
                                            PROPOSED ORDER                               PAGE3


12.   On October 9, 2006, all intervenors, except ETC, filed testimony and supporting
      documents addressing EGSI's application and direct testimony, and State and Port Arthur
      also filed statements of position.


13.   All intervenors that filed testimony recommended various adjustments to the Hurricane
      Rita reconstruction costs and proposed carrying costs, or to the proposed
      functionalization and allocation, requested by EGSI.


14.   On October 12, 2006, State and TIEC filed cross-rebuttal testimony.


15.   On October 16, 2006, Commission Staff filed its testimony, which, among other things,
      recommended a lower carrying cost rate than EGSI had requested, and also filed a
      statement of position.


16.   On October 17, 2006, the Commission issued Order No. 9, which, among other things,
      directed parties not prefiling direct testimony but wishing to participate in the hearing on
      the merits to file a statement of position no later than October 24, 2006.


17.   On October 23, 2006, EGSI filed rebuttal testimony and a statement of position.


18.   On October 27, 2006, the Commission issued Order No. 12, which ruled on EGSI's
      objections and motion to strike various portions of the pre-filed testimony and supporting
      documents filed by the intervenors.


19.   At a prehearing conference convened on October 30, 2006, the Commission admitted into
      evidence: (a) all of the parties' pre-filed testimony and supporting documents, except as
      modified or stuck by Order No. 12 and the parties' errata to their pre-filed evidence; (b)
      the parties' cross-examination exhibits; and (c) the parties' optional completeness
      exhibits. The Commission took under advisement the admissibility of several proffered
      exhibits pending its review of motions filed in response to Order No. 12. In addition,
      under Order No. 9, the parties were to convene on November 1, 2006, before the start of
PUC DOCKET NO. 32907
                                          PROPOSED ORDER                                PAGE4


      the hearing on the merits, for a continuation of the prehearing conference to address any
      remaining exhibit items.


20.   On October 30, 2006, after the prehearing conference was concluded, the Commission
      issued Order No. 13, which ruled on State's and EGSI's motions filed in response to
      Order No. 12, clarified which portions of pre-filed testimony and supporting documents
      were modified or struck by Order No. 12, and admitted additional cross-examination
      exhibits.


21.   On November 1, 2006, at the prehearing conference convened before the start of the
      hearing on the merits, the parties present requested a delay in the start of the hearing on
      the merits to enable them to continue settlement talks. The Commission granted the
      request.


22.   Later in the morning of November 1, 2006, the parties present announced that they had
      reached a settlement on all issues, stated that there was no need to conduct a hearing on
      the merits, and requested the opportunity to prepare a settlement agreement to file with
      the Commission. The Commission granted the request.


23.   On November 17, 2006, EGSI filed the Agreement, which resolves all issues in this
      docket, on behalf of itself, Commission Staff, and all active parties. The filing stated on
      behalf of ETC that ETC neither supports nor objects to the Agreement.

The Agreement
24.   Under the Agreement, the amount of EGSI' s reasonable and necessary hurricane
      reconstruction costs incurred through March 31, 2006 that is eligible for recovery and
      securitization is $381,236,384 plus carrying costs, as set forth in findings of fact 26
      through 35.


25.   The Agreement does not reflect or determine resolution of any hurricane reconstruction
      costs that were charged to EGSI's books after March 31, 2006.
PUC DOCKET NO. 32907
                                                 PROPOSED ORDER                          PAGES


26.   In addition to $381,236,384, the Agreement authorizes EGSI to include in hurricane
      reconstruction costs and securitize carrying costs at the rate of 7.9% per annum as
      reflected in Attachment A to this Order, 3 from the later of October 15, 2005 or the date
      incurred until the issuance of securitization bonds. The balance upon which carrying
      costs are determined will be reduced by the amount of insurance payments when received
      as provided in findings of fact 27 through 30.


27.   The Agreement directs EGSI to credit $65.7 million in the manner described in finding of
      fact 35, reflecting EGSI's expectation that it will receive insurance payments in that
      amount (Texas Retail).


28.   Under the Agreement, carrying costs at the rate referenced in finding of fact 26 shall
      apply to: (1) any portion of the $65.7 million referenced in finding of fact 27 not actually
      received by EGSI, until EGSI actually receives (Texas Retail) such payments; and (2) the
      trued-up amount, as provided in finding of fact 29, until such trued-up amount (plus
      associated carrying costs at the rate of 7.9% per annum) is recovered in base rates.


29.   The Agreement provides that after EGSI receives all insurance payments related to
      Hurricane Rita, the $65.7 million credited, as provided in finding of fact 27, shall be
      trued up to reflect the difference between the $65.7 million credited and all insurance
      payments actually received by EGSI related to Hurricane Rita for Texas Retail.


30.   Under the Agreement, in the event EGSI receives insurance payments related to
      Hurricane Rita for Texas Retail in excess of $65.7 million after the Commission's
      issuance of a financing order in the financing order proceeding, such payments shall be
      passed through to ratepayers in the form of a rider with carrying costs calculated on the
      unamortized balance of such payments at the rate of 7 .9% per annum.


31.   The Agreement directs EGSI to continue to pursue EGSI' s application for proceeds from
      governmental grants.


      3
          Attachment A is a copy of Exhibit A to the Agreement.    .
                                                                  2~
PUC DOCKET NO. 32907
                                          PROPOSED ORDER                                 PAGE6


32.   With regard to the treatment of grant proceeds distributed prior to securitization, the
      Agreement provides as follows:


      A.     Any proceeds from governmental grants distributed directly to EGSI before the
             Commission issues a financing order shall be administered in a manner consistent
             with the conditions and directions of the grant, and, if consistent with the
             conditions and directions of the grant, shall be used to reduce the amount
             securitized. For illustrative purposes with respect to the preceding sentence, a
             reduction in the securitized amount is not considered consistent with the
             conditions and directions of the grant when, based on the cost allocation provided
             in the Agreement, such a reduction in the amount securitized would result in rates
             (transition charges) that would allocate the credit or reduction associated with the
             grant proceeds among customers or customer classes in a manner inconsistent
             with the conditions and instructions of the grant.


      B.     If a reduction of the securitized amount is not consistent with the conditions and
             directions of the grant as described in finding of fact 32, item A, and the grant
             does not prescribe carrying costs on the grant proceeds (either explicitly or
             implicitly, e.g., by instructing that the proceeds be escrowed or treated similarly),
             EGSI will reduce the securitized amount by the amount of carrying costs on the
             grant proceeds, calculated at 7 .9 % per annum from EGSI' s actual receipt of grant
             proceeds until the issuance of securitization bonds.


33.   The Agreement provides that any proceeds from governmental grants distributed directly
      to EGSI after the Commission's issuance of a financing order shall be administered in a
      manner consistent with the conditions and directions of the grant, and, if consistent with
      the conditions and directions of the grant, shall be passed through to ratepayers in the
      form of a rider with carrying costs calculated on the unamortized balance of such
      proceeds at the rate of7.9% per annum.


34.   In regard to the receipt of governmental grant proceeds as described in findings of fact 32
      and 33, the Agreement further provides that, in any event, any reduction in rates
PUC DOCKET NO. 32907
                                          PROPOSED ORDER                                PAGE7


      associated with the receipt of governmental grant proceeds shall be no greater than the
      amount of such proceeds, subject to the calculation of carrying costs provided in findings
      of fact 32 and 33.


35.   Under the Agreement, the total dollar amount eligible to be securitized in the financing
      order proceeding (as reflected in Attachment A to this Order) shall be: $381,236,384 plus
      carrying costs at the rate and for the time period specified in findings of fact 26 through
      30, minus $65.7 million related to insurance, plus all other qualified costs, to be
      determined by the Commission in the financing order proceeding, provided for in PURA
      § 39.460(d).


36.   The Agreement provides that the present value of the benefit, if any, of accumulated
      deferred federal income taxes and method of handling such benefit will be part ofEGSI's
      presentation in the financing order proceeding and subject to the Commission's
      determination about how such benefit, if any, should be treated in the financing order or a
      subsequent proceeding.


37.   Under the Agreement: (a) the functionalization and allocation methodology proposed by
      EGSI in its filed case shall be utilized in the financing order proceeding; and (b)
      adjustments described in findings of fact 24 through 36 shall be functionalized and
      allocated pro rata in the same manner as proposed by EGSI in its filed case.


38.   The Agreement includes standard prov1s10ns regarding waiver, general terms and
      conditions, lack of precedential effect, and termination of the Agreement in the event the
      Commission does not accept the Agreement as presented.


39.   The Agreement resolves all issues of fact and law applicable to this docket.


40.   Approval of the Agreement is in the public interest.
PUC DOCKET NO. 32907
                                          PROPOSED ORDER                                   PAGES


                                   II. Conclusions of Law

1.    EGSI is a public utility as that term is defined in §§ 11.004 and 31.002 of PURA.


2.    The Commission has jurisdiction over this proceeding under PURA §§ 39.458-.463.


3.    EGSI provided appropriate notice of this proceeding in accordance with P.U.C. PROC.
      R. 22.55.


4.    EGSI's application was processed in accordance with PURA §§ 39.458-.463 and the
      Administrative Procedure Act, TEX. Gov'T CODE ANN. §§ 2001.001-.902 (Vernon 2000
      & Supp. 2006).


5.    PURA §§ 39.458-.463 allow, among other things, EGSI to obtain timely recovery of
      reasonable and necessary Hurricane Rita reconstruction costs and to use securitization
      financing to recover those costs.


6.    The functionalization and allocation methodology proposed by EGSI in its filed case
      complies with PURA§ 39.460(g).


7.    The evidentiary record, which includes testimony and exhibits filed by EGSI,
      Commission Staff, Cities, TIEC, OPC, and State, supports the Agreement.


8.    Because the Agreement is the result of an unopposed agreement among the parties, an
      adjudicatory hearing is not required to process EGSI's application in this docket.


                                 III. Ordering Paragraphs

1.    EGSI's request for a determination of the dollar amount of its Hurricane Rita
      reconstruction cost, incurred through March 31, 2006, plus carrying costs, that are
      eligible for recovery and securitization in the financing order proceeding, as described in
      finding of fact 35 and the Agreement, is approved.
PUC DOCKET NO. 32907
                                           PROPOSED ORDER                              PAGE9


2.    In the financing order proceeding, the hurricane reconstruction costs shall be
      functionalized and the associated revenue requirement allocated in the manner proposed
      by EGSI in its case filed on July 5, 2006.


3.    EGSI shall comply with the true-up provisions regarding insurance payments as set out in
      findings of fact 28 through 30.


4.    EGSI shall treat governmental grant proceeds in the manner set out in findings of fact 32
      through 34.


5.    EGSI shall continue to pursue its application for proceeds from governmental grants.


6.    Entry of this Order does not indicate the Commission's endorsement or approval of any
      principle or methodology that may underlie the Agreement. Neither shall the entry of the
      Order be regarded as binding precedent as to the appropriateness of any principle
      underlying the Agreement.


7.    All other motions, requests for entry of specific findings of fact and conclusions of law,
      and any other request for general or specific relief, if not expressly granted herein, are
      denied.

      SIGNED AT AUSTIN, TEXAS the _ _ _ _ day of _ _ _ _ _ _ _ _ 2006.

                                            PUBLIC UTILITY COMMISSION OF TEXAS


                                            PAUL HUDSON, CHAIRMAN


                                            JULIE PARSLEY, COMMISSIONER


                                            BARRY T. SMITHERMAN, COMMISSIONER
Entergy Gulf States, Inc.                                                                                                                    Docket No. 32907
Rita Storm Restoration Costs for TX                                                                                                             Attachment A
Estimate of Carrying Cost for TX Retail                                                                                                            Page 1of1
For Costs Incurred September 2005 - March 2006
(Amounts in Dollars)



TX Retall Carrying Cost

  Beginning                                                 Adjusted Cost                                                                        Estimated
   Month of         TX Retail           Accrual               Including                              Balance for           Settlement            Insurance
 Carrying Cost        Cost             Adjustment            Settlement         Carrying Cost       Carrying Costs        Adjustments            Payments
    Sep OS           1,552,686                                    1,504,592                               1,504,592            (48,093)
    Oct OS          66,174,846               (475,471)          63,649,651               219,419         65,373,662         (2,049,724)
    Nov OS          82,799,332                147,669           80,382,344               694,968        146,450,974         (2,564,657)
    Decos           58,598,197               (361,211)          56,421,944            1,149,858         204,022,776         (1,815,042)
    Jan 06          34,649,048                626,801           34,202,617            1,455,734         239,681,126         (1,073,232)
    Feb 06          55,318,008               (134,812)          53,469,755            1,753,905         294,904,786         (1,713,440)
    Mar06           88,324,964            (35,544,631)          50,044,523            2, 106, 186       347,055,496         (2,735,810)
    Apr-06                                 25,086,733           25,086,733            2,367,359         374,509,588
    May-06                                 10,654,922            10,654,922           2,500,594         387,665, 104
    Jun-06                                                                            2,552,129         390,217,232
     Jul-06                                                                           2,568,930         392,786, 162
    Aug-06                                                                            2,585,842         383,228,245                               (12, 143,760)
    Sep-06                                                                            2,522,919         385,751,164
    Oct-06                                                                            2,539,528         388,290,692
    Nov-06                                                                            2,556,247         390,846,940
    Oec-06                                                                            2,573,076         393,420,015
    Jan-07                                                                            2,590,015         396,010,030
    Feb-07                                                                            2,607,066         398,617,096
    Mar-07                                                                            2,624,229         401,241,326
    Apr-07                                                                            2,641,505         403,882,831
    May-07                                                                            2,658,895         406,541,726
Sub-Totals         387,417,080                                 375,417,080           43,268,406                               (12,000,000)        (12, 143,760)

LessAFUOC
 Sep 05 - Mar 06                                                                     (5,819,304)

Total Carrying Costs                                                                 37,449,102

Summary

TX Retail Costs Above                                          375,417,080
AFUOC                                                            5,819,304
Total TX Retail Costs Per Exh JDW-2 Less Seti. Adj.            381,236,384

Total Carrying Costs                                            37,449,102

Total to Recover Assuming a June 1 Securitization              418,685,486
(Carrying costs to be calculated until issuance of bonds)

Ins. to Remove for Securitization (TX Retail Amt.)              65,700,000

Total to Securitize Assuming a June 1 Securitization           352,985,486


Notes:
TX Retail Cost excludes AFUDC.
Accruals Adjustment subtracts costs that are accrued but not yet paid. Accruals are assumed to be paid in full by May 2006.
Carrying Cost= (Current Month Adjusted Cost• 1/2 Month + Prior Month Balance to Recover)• Carrying Cost
Hurricane Rita tax benefits have not been realized as the Company is in a net operating loss carryforward position.
Amounts may not sum to totals due to rounding.
Plus all other qualified costs provided for in Section 39.460(d) of PURA.

Carrying Cost                                                                              7.90%
                                   PUC DOCKET NO. 34800
                                 SOAH DOCKET NO. XXX-XX-XXXX


APPLICATION OF ENTERGY                                §
GULF ST ATES, INC. FOR                                §
AUTHORITY TO CHANGE RATES                             §
AND TO RECONCILE FUEL                                 §
COSTS                                                 §

                                                   ORDER

                                                                                                             1
        This order addresses the application of Entergy Gulf States, Inc. (EGSI)                                 for
authority to change rates and reconcile fuel costs. The docket was processed in accordance
with applicable statutes and Public Utility Commission of Texas rules.                                     EGSI,
Commission Staff, the Office of Public Utility Counsel (OPC), the Community
Associations of the Woodlands (CATW), the Entergy Texas, Inc. Service Area Cities'
Steering Committee (Cities), the State of Texas, Texas Industrial Energy Consumers
(TIEC), Texas Legal Services Center (TLSC), Texas Ratepayers' Organization to Save
Energy (Texas ROSE), Wal-Mart Stores Texas, LLC , through their duly authorized
representatives (Wal-Mart) (collectively, signatories) filed a stipulation and settlement
agreement that resolves all of the issues in this proceeding. The Kroger Company and TX
Energy, LLC did not sign the stipulation and do not oppose it.                           Consistent with the
stipulation, EGSI's application is approved.

        The Commission adopts the following findings of fact and conclusions of law:


                                            I. Findings of Fact

Procedural History

1.       On September 26, 2007, EGSI filed an application for approval of: ( 1) base rate
         tariffs and riders designed to collect a total non-fuel revenue requirement for the



         1
          On December 31, 2007, EGSI jurisdictionally separated pursuant to      * 39.452( e) of the Public Utility
Regulatory Act (PURA), TEX. UTIL. CODE ANN. Title 2 and Entergy Texas, Inc. (ETI) succeeded to EGSI's certificate of
PUC Docket No. 34800                                Order                                          Page 2of15
SOAH Docket No. XXX-XX-XXXX


        Texas retail jurisdiction of $605 million; (2) a set of proposed tariff schedules
        presented in the Electric Utility Rate Filing Package for Generating Utilities (RFP)
        accompanying EGSI's application; (3) a request for final reconciliation of EGSI's
        fuel and purchased power costs for the reconciliation period from January 1, 2006
        to March 31, 2007, as well as deferred costs from prior proceedings; and (4) certain
        waivers to the instructions in RFP Schedule V accompanying EGSI's application.

2.      The 12-month test year used in EGSI's application ended on March 31, 2007.

3.       EGSI provided notice by publication for four consecutive weeks before the
         effective date of the proposed rate change in newspapers having general circulation
        in each county of EGSI's Texas service territory.                  EGSI also mailed notice of its
         proposed rate change to all of its customers. Additionally, EGSI timely served
         notice of its statement of intent to change rates on all municipalities retaining
         original jurisdiction over its rates and services.

4.       The following parties were granted intervenor status in this docket: OPC, Alliance
         for Retail Markets (ARM), CATW, Cities, Kroger Company, State, TIEC, TLSC,
         Texas ROSE, TX Energy, LLC, and Wal-Mart.2 Commission Staff was also a
         participant in this docket.

5.       On October 1, 2007, the Commission referred this case to the State Office of
         Administrative Hearings (SOAH) for processing.

6.       EGSI appealed the rate decisions adopted by the Cities of Chester, Woodville,
         Ames, Dayton, Devers, Liberty, New Waverly, Riverside, Trinity, Bedias,
         Bremond, Caldwell, Calvert, Franklin, Madisonville, Somerville, Patton Village,
         Cut and Shoot, Willis, Plum Grove, Shepherd, Oak Ridge North, Normangee,
         Daisetta, Hardin, Corrigan, Groveton, Anderson, Kosse, North Cleveland,
         Woodloch, Midway, Panorama Village, Taylor Landing, Rose Hill Acres, China,
         Hearne, Bevil Oaks, Colmesneil, Kountz, Nome, Lumberton, and Todd Mission.


convenience and necessity for its Texas retail jurisdiction. For continuity and ease of reference, EGSI, Commission
Staff, and intervenors have continued to make reference to EGSI for purposes of pleadings in this docket.
         2
           OPC, ARM, Cities, Kroger Company, State, and TIEC were granted party status on October 22, 2007. See
Prehearing Conference Tr. at 6.
PUC Docket No. 34800                      Order                              Page 3of15
SOAH Docket No. XXX-XX-XXXX


7.     As provided for in Order Nos. 3, 9, 12, 14, and 23, the SOAH administrative law
       judges (ALJs) consolidated EGSI's appeals of the rate decisions adopted by the
       cities in Finding of Fact No. 6.

8.     Cities participated in this case representing the Cities of Beaumont, Bridge City,
       Conroe, Groves, Houston, Huntsville, Navasota, Nederland, Orange, Pine Forest,
       Pinehurst, Port Arthur, Port Neches, Rose City, Shenandoah, Silsbee, Sour Lake,
       Vidor, and West Orange. These municipalities have adopted rates consistent with
       the stipulation discussed below.

9.     The Commission established in its Order on Appeal of Order No. 8 an effective
       date for EGSI's proposed rate change of September 26, 2008.

10.    On April 8, 2008, the State filed a motion for partial summary decision regarding
       the continued applicability of the 20% base rate discount for state institutions of
       higher education under § 36.351 of the Public Utility Regulatory Act, TEX. UTIL.
       CODE ANN.§§ 11.001-66.016 (Vernon 2007 & Supp. 2008) (PURA).

11.    On July 16, 2008, the SOAH ALJs issued a proposal for decision (PFD)
       recommending that the Commission grant the State's April 18, 2008 motion for
       partial summary decision.

12.    On August 15, 2008, the Commission entered an order adopting the PFD on the
       State's motion for partial summary decision.

13.    The Commission entered an order on November 4, 2008, extending the effective
       date ofEGSI's proposed rate change until November 27, 2008.

14.    Commission Staff, State, and TIEC filed a non-unanimous stipulation (NUS) on
       May 19, 2008. EGSI and certain other parties filed a separate NUS on May 20,
       2008. 3 The EGSI NUS was opposed by Commission Staff, State, and TIEC. A
       hearing was held on both NUSs on June 23 through July 2, 2008.

15.    At Open Meetings on October 23 and November 5, 2008, the Commission
       considered a PFD from the SOAH ALJ s which recommended resolution of the rate
PUC Docket No. 34800                              Order                        Page 4of15
SOAH Docket No. XXX-XX-XXXX


       case through adoption of the EGSI NUS. On November 7, 2008, the Commission
       issued its order on remand rejecting the PFD and remanding the docket to SOAH
       for a hearing on the merits of EGSI's original application.

16.    During the November 5, 2008 Open Meeting, EGSI agreed to extend the statutory
       jurisdictional deadline in this docket to March 2, 2009. EGSI subsequently agreed
       to extend the statutory jurisdictional deadline to March 16, 2009. 4

17.    The SOAH ALJs granted ARM's motion to withdraw as an intervenor on
       December 2, 2008, pursuant to Order No. 49.

18.    The hearing on the merits on remand took place on December 3 and 4, 2008, and
       December 8 through December 12, 2008.                   The hearing was recessed on
       December 12, 2008, in order to allow the parties to work on concluding a
       settlement.

19.    On December 16, 2008, the signatories submitted a settlement term sheet to reflect
       their agreement in principle resolving all outstanding issues regarding EGSI's
       application, including those issues raised by the Commission in its November 7,
       2008 order on remand.

20.    On December 16, 2008, the signatories submitted an agreed motion to implement
       interim rates.

21.    On December 19, 2008, the SOAH ALJs filed Order No. 52, granting interim
       approval of rates consistent with the settlement term sheet, effective with bills
       rendered on and after January 28, 2009, for usage on and after December 19, 2008.

22.    On February 5, 2009, the signatories submitted a stipulation resolving all
       outstanding issues in this docket.

23.    On February 10, 2009, the SOAH ALJs filed Order No. 56, returning this docket to
       the Commission.



       3
           The EGSI NUS was subsequently amended on June 27, 2008.
       4
           EGSI letter filed February 18, 2009.
PUC Docket No. 34800                        Order                             Page 5of15
SOAH Docket No. XXX-XX-XXXX


Description of the Stipulation and Settlement Agreement

24.    The signatories agree that EGSI will institute an overall mcrease in base rate
       revenues of $46. 7 million.

25.    The signatories agree to a reasonable return on equity for EGSI of 10.00%.

26.    The signatories agree that the cost of service underlying the base-rate revenue
       increase does not include any unreasonable or unjust expenses.

27.    The signatories agree that EGSI will implement a rate-case-expense rider to recover
       $2.3 million per year for three years. The rate-case expenses will be allocated to
       customer classes based on total base-rate revenues. The rates established under the
       rate-case expense rider will be determined based on energy consumption in
       kilowatt-hours (kWh), except for the Large Industrial Power Service (LIPS)
       customer class, whose rates will be set on a kilowatt (kW) basis.

28.    The Signatories agree to leave the mechanisms for recovery of EGSI's municipal
       franchise-fee riders unchanged as a result of this docket.

29.    The Signatories agree that EGSl's proposed Market Value Energy Rider (MYER)
       will not be offered as a result of this docket.

30.    The signatories agree that the Incremental Purchased Capacity Recovery Rider
       (IPCR) will expire contemporaneously with the implementation of rates approved
        in Order No. 52.

31.    The signatories agree that the base-rate revenue increase, the rate-case expense
       rider and the municipal franchise-fee riders addressed in the stipulation became
        effective for bills rendered on and after January 28, 2009 for usage on and after
        December 19, 2008, as approved in Order No. 52.

32.     The signatories reached the following specific agreements regarding rate design as
        a part of the overall resolution of this docket:

        a.      Supplemental Short Term Service (SSTS). Rate Schedule SSTS will
                terminate six months after a final, appealable order approving the
                stipulation is issued by the Commission in this docket. Beginning with the
PUC Docket No. 34800                         Order                                 Page 6of15
SOAH Docket No. XXX-XX-XXXX


              base rates implemented as a result of this stipulation, EGSI will bill SSTS
              usage as follows: (SSTS charges+ LIPS charges)/2.

       b.     Interruptible Service (IS). Rate Schedule IS will be modified as follows:

              1.        30-minute notice service is eliminated;

               ii.      The credit for 5-minute notice service 1s reduced to $3.75/kW-
              month;

               111.     The credit for no-notice service is reduced to $4.88/kW-month;

               1v.      The credits shall be applied to the· LIPS and LIPS-Time of Use
               (TOU) tariffs (current High Load Factor Service (HLFS) and Large Power
               Service (LPS) customers will be transferred to LIPS); and

               v.       Rate Schedule IS remains closed to new business.

       c.      Competitive Generation Service. EGSI's competitive generation-service
               proposal shall not be withdrawn, but shall be severed from this docket and
               addr('<::<::ed in a separate docket wherein the Commission will (a) exercise its
               authority to approve, reject, or modify EGSI's proposal; and (b) address
               reCOV'         • any costs unrecovered as a result of the implementation of the


       ,J
       \.J              ~   'neons Electric Service Charges. No change shall be made to
               Miscellaneous Electric Service Charges.

       e.      Lighting Class Rates. Lighting-class rates for all lighting fixtures shall be
               designed in a manner so that each fixture is charged a uniform base-rate
               percentage increase as established for the entire lighting class.

       f.      Additional Facilities Charge (AFC).           Rate Schedule AFC, governing
               additional-facilities charge, will be designed to result in a reduction to
               1.49%, with the resulting revenue reduction allocated among those
               customer classes with AFC revenue based on the percentage of AFC
               revenues in each customer class.
PUC Docket No. 34800                       Order                               Page 7of15
SOAH Docket No. XXX-XX-XXXX


       g.      Economic as Available Power Service/Standby Maintenance Service.
               No substantive changes shall be made as a result of this docket to: (a) Rate
               Schedule EAPS, governing Economic-as-Available Power Service; or (b)
               Rate Schedule SMS, governing Standby Maintenance Service.

       h.      Interconnection Terms and Conditions. No changes shall be made as a
               result of this docket to EGSI's terms and conditions regarding costs for
               interconnection of customers.

       L       Electric Extension Policy. No changes shall be made as a result of this
               docket to EGSI's electric extension policy.

       J.      Large Interruptible Power Service. The signatories stipulate that the
               contract demand ratchet provisions in Rate Schedule LIPS will be retained;
               provided, however, that the billing demand provision contained in
               Paragraph V of Rate Schedule SSTS will no longer apply to customers
               taking service under Rate Schedule LIPS after Rate Schedule SSTS
               terminates.

33.    The signatories agree to the class-cost allocation set forth in Attachment A to the
       stipulation and further agree that this allocation is reasonable.

34.    The signatories agree to a River Bend nuclear generating station 20-year life
       extension adjustment to EGSI's calculation of nuclear depreciation and
       decommissioning costs effective January 1, 2009.

35.    The signatories agree that EGSI will reduce depreciation expense related to EGSI's
       steam production plants by the amount of $2,731,478 on a total Texas retail basis
        effective January 1, 2009.

36.    The signatories agree that EGSI will present a new depreciation study as part of its
        next base-rate case, or by January 5, 2010, whichever is earlier.

37.     The signatories agree that the base-rate increase, rate riders, and associated rate
        design and class-cost allocation agreed to in the stipulation are reasonable and are
PUC Docket No. 34800                         Order                                   Page 8of15
SOAH Docket No. XXX-XX-XXXX


       reflected in the rate schedules approved by Order No. 52 and revised by errata
       filings on December 22, 2008, January 27, 2009, and March 5, 2009.

38.    The signatories agree that EGSI will fund its Public Benefit Fund at an annualized
       amount of $2 million.

39.    In order to include a greater portion of the eligible population in the Public Benefit
       Fund program, EGSI agrees to use its best efforts to contract for and implement an
       automatic enrollment program.         EGSI's automatic enrollment program will be
       modeled upon the matching procedures used by other Texas utilities to identify
       eligible customers and will be implemented within 30 days of the Commission's
       filing of the final order in this case.

40.    The signatories agree that EGSI will amend its low-income energy-efficiency
       program on a trial basis as specified in the stipulation.

41.    The signatories agree that the amendment of EGSI' s low-income energy-efficiency
       program does not increase base rates to recover uncollected expenses associated
       with revenues billed under EGSI's energy-efficiency rider approved in Docket
       No. 35626.5

42.    The signatories agree to a fuel disallowance of $4.5 million, booked in the month
       of a final Commission order approving the application, consistent with the
        stipulation.

43.     The signatories agree to adopt Commission Staffs position on the following
        resolution of fuel-related matters set out in Commission Staffs pre-filed direct
        testimony: (a) recovery of sulfur dioxide (S02) and nitrous oxide (NOx) emissions
        revenues recorded in Account 411.8 and expenses recorded in Account 509 will be
        allowed as eligible fuel expense going forward until further order of the
                                                        .
        Commission realigning such costs; (b) special circumstances should be granted to
        treat the costs of natural-gas call options incurred during the reconciliation period


        5
        Application of Entergy Texas, Inc. for Approval of an Energy Efficiency Cost Recovery Factor
(EECRF) Pursuant to PURA§ 39.905(b) and P.UC. Subst. R. 25.181(/), Docket No. 35626, Order (Aug. 14,
2008).
PUC Docket No. 34800                       Order                                Page 9of15
SOAH Docket No. XXX-XX-XXXX


       as eligible fuel expense; (c) good cause exists to sever and defer the River Bend
       performance-based ratemaking (PBR) calculation for the final seven months of the
       reconciliation period to EGSI's next fuel reconciliation proceeding; and (d) the
       River Bend PBR plan should terminate in light of EGSI's jurisdictional separation.

Evidence Supporting the Stipulation and Agreement

44.    Considered in light of (a) the pre-filed testimony by the parties entered into
       evidence, and (b) the additional evidence and testimony presented by the parties
       during the course of the hearing on the merits on EGSI's application, the stipulation
       is the result of compromise from each party, and these efforts, as well as the overall
       result of the stipulation viewed in light of the record evidence as a whole, support
       the reasonableness and benefits of the terms of the stipulation.

45.    The evidence addressed in finding of fact 44 demonstrates that the rates, terms, and
       conditions resulting from the stipulation are just and reasonable and consistent with
       the public interest when the merits of the issues contested by Commission Staff and
       intervenors are considered.

46.    The stipulated revenue requirement does not include any amounts for financial-
       based incentive compensation.

47.    To the extent that affiliate costs are included in the stipulated revenue requirement
       and fuel expense, they are reasonable and necessary for each class of affiliate costs
       presented in EGSI' s application.

48.    To the extent that affiliate costs are included in the stipulated revenue requirement
       and fuel expense, the price charged to EGSI is not higher than the prices charged by
       the supplying affiliate for the same item or class of items to its other affiliates or
       divisions, or a non-affiliated person within the same market area or having the
        same market conditions.

49.     The Texas retail revenue requirement in the stipulation does not include any of the
        following expenses, whether allocated or direct-billed to EGSI: legislative
        advocacy expenses; entertainment; charitable contributions; advertising expense to
        promote the increased consumption of electricity or to promote the image of the
PUC Docket No. 34800                       Order                               Page 10of15
SOAH Docket No. XXX-XX-XXXX


       electric utility industry; advertising products marketed by other affiliates; civil
       penalties or fines; any other expenses listed in PURA §§ 36.061, 36.062, and
       36.063; payments made to cover costs of an accident, equipment failure, or
       negligence at a utility facility owned by a person or governmental body not selling
       power inside the State of Texas (except those made under an insurance or risk-
       sharing arrangement executed before the date of loss); the costs for processing a
       refund or credit under PURA § 36.11 O; any profit or loss that results from the sale
       of merchandise not integral to providing utility service; construction work in
       progress in rate base; or plant held for future use in rate base.

50.    EGSI's current supplemental short-term service, Schedule SSTS, should be
       terminated within six months after the filing of a final, appealable Commission
       order in this docket, as provided for in the stipulation.

51.    It is reasonable to modify EGSI's current interruptible service, Schedule IS, in
       accordance with the terms and conditions of the stipulation.

52.    It is reasonable in light of the compromise reached in the stipulation for no
       substantive modifications to be made to EGSI's economic as-available power
       service, Schedule EAPS, or standby maintenance service, Schedule SMS.

53.    The depreciation and decommissioning adjustments for nuclear production assets
       agreed to in the stipulation and consistent with Louisiana rate treatment are
       reasonable.

54.    The depreciation adjustments to EGSl's steam production assets agreed to in the
       stipulation are reasonable.

55.    The increase in storm cost accruals provided for in the stipulation is reasonable.

56.    The low-income programs provided for in the stipulation are reasonable.

57.     EGSI's energy-efficiency costs are recovered through a rider approved by the
       Commission in Docket No. 35626.

58.    The PBR plan for the River Bend nuclear generating station contemplates an
       annual calculation of penalties and rewards. Good cause exists to sever and defer
PUC Docket No. 34800                       Order                               Page 11of15
SOAH Docket No. XXX-XX-XXXX


       the PBR calculation for the final seven months of the reconciliation period to
       EGSI's next fuel reconciliation proceeding.

59.    It is reasonable to terminate the application of the PBR plan to the River Bend
       operations on and after January 1, 2008 when Entergy Texas, Inc. no longer has an
       ownership interest in River Bend.

60.    EGSI is entitled to a special circumstances exception for the cost of the natural-gas
       call options because they resulted in increased reliability of supply and reduced fuel
       expense.

61.    The class allocation methodologies described in the stipulation are reasonable.

62.    The total level of invested capital in the Texas retail revenue requirement 1s
       reasonable.

63.    The EGSI stipulation proposes to collect the existing incremental franchise fees of
       the Cities of Beaumont, Port Arthur, and Conroe as a municipal franchise-fee rider.
       The Commission has reviewed its finding in paragraph ILE of its remand order of
       November 7, 2008 and determines that the existing incremental franchise fees were
       the result of franchise agreements adopted subsequent to the passage of PURA
       § 39.456.



                                II. Conclusions of Law


1.     EGSI is a public utility as that term is defined in PURA § 11.004( 1) and an electric
       utility as that term is defined in PURA § 31.002(6).

2.     The Commission exercises regulatory authority over EGSI and jurisdiction over the
       subject matter of this application pursuant to PURA §§ 14.001, 32.001, 32.101,
       33.002, 33.051, 36.001-36.111, 36.203, 39.452, and 39.455.

3.     SOAH had jurisdiction over matters related to the conduct of the hearing and the
       preparation of a proposal for decision in this docket, pursuant to PURA § 14.053
        and TEX. Gov'T CODE ANN. § 2003.049.
PUC Docket No. 34800                                    Order                         Page 12of15
SOAH Docket No. XXX-XX-XXXX


4.        This docket was processed in accordance with the requirements of PURA and the
          Texas Administrative Procedure Act. 6

5.        EGSI provided notice of its application in compliance with PURA§ 36.103, P.U.C.
          PROC. R. 22.5l(a), and P.U.C. SUBST. R. 25.235(b)(l)-(3).

6.        This docket contains no remaining contested issues of fact or law.

7.        The stipulation, taken as a whole, is a just and reasonable resolution of all the
          issues it addresses, results in just and reasonable rates, terms and conditions, is
          supported by a preponderance of the credible evidence in the record, is consistent
          with the relevant provisions of PURA, and is consistent with the public interest.

8.        EGSI has properly accounted for the amount of fuel and IPCR-related revenues
          collected pursuant to the fuel factor and Rider IPCR during the reconciliation
          period.

9         The revenue requirement, cost allocation, revenue distribution, and rate design
          implementine: the stipulation result in rates that are just and reasonable, comply
                  •• 1~   ratemaking provisions in PURA, and are not unreasonably discriminatory,
          prcfrr :tial,       t..           ..;ial.
1    ;~
          \)ever'-'          .•1    c'0SI's proposed competitive generation service into a separate
               ·ket :::iL         ~it r,   ',,,addressed separately is reasonable.

          EGS1 ,:.          ~mi     'cd to a special circumstances exception under P.U.C. SUBST. R.
          25.236(a)(6) for :he cost of natural gas call options.

12.       Consistent with the stipulation, good cause exists to treat EGSl's emissions
          revenues and expenses referenced in finding of fact 43 as eligible fuel expense on a
          going-forward basis until further order of the Commission realigning such costs.

13.       Based on the evidence in this docket, the overall total invested capital through the
          end of the test year meets the requirement in PURA§ 36.053(a) that electric utility
          rates be based on the original cost, less depreciation, of property used by and useful
          to the utility in providing service.

          6
              TEX. GOV'T. CODE ANN. Chapter 2001(Vernon2000 and Supp. 2007).
PUC Docket No. 34800                       Order                              Page 13of15
SOAH Docket No. XXX-XX-XXXX


14.    The Commission has reviewed its finding in paragraph ILE of its remand order of
       November 7, 2008 and determines that because the existing incremental franchise
       fees were the result of franchise agreements subsequent to the passage of PURA
       § 39.456, they qualify as new franchise agreements and are therefore in compliance
       with PURA§ 39.456 when recovered as a municipal franchise-fee rider.

15.    The final resolution of the instant docket does not impose any conditions,
       obligations, or limitations on EGSI's right to file a base-rate proceeding and obtain
       rate relief in accordance with PURA.

16.    Consistent with the stipulation, EGSI has met its burden of proof in demonstrating
       that it is entitled to the agreed upon level of Texas retail base-rate and rider
       revenue.

17.    Consistent with the stipulation and PURA, EGSI has met its burden of proof in
       demonstrating that the rates are just and reasonable.


                               III. Ordering Paragraphs


       In accordance with these findings of fact and conclusions of law, the Commission
issues the following orders:


1.     Consistent with the stipulation, EGSI's application for authority to (a) change its
       rates; (b) reconcile its fuel and purchased power costs for the Reconciliation Period
       from January 1, 2006 to March 31, 2007, as well as deferred costs from prior
       proceedings; and (c) for other related relief is approved.

2.     Consistent with the stipulation, the rates, terms, and conditions described in this
       order are approved.

3.     Consistent with the stipulation, the tariffs and riders approved on an interim basis
       by Order No. 52 and revised by errata on December 22, 2008, January 27, 2009,
        and March 5, 2009, are approved.
PUC Docket No. 34800                         Order                                Page 14of15
SOAH Docket No. XXX-XX-XXXX


4.     Consistent with the stipulation, EGSI shall implement the low-income programs
       described in this order.

5.     Consistent with the stipulation, EGSI's Competitive Generation Services tariff is
       severed from this docket and shall be addressed in Application of Entergy Texas,
       Inc.for Approval of Competitive Generation Services Tariff, Docket No. 36713.

6.     Consistent with the stipulation, EGSI's storm-cost accruals shall be increased by $2
       million for a total accrual of $3.65 million annually beginning January l, 2009,
       which amount will be incorporated in revenues recovered through base rates.

7.     Consistent with the stipulation, EGSI shall terminate rate schedule SSTS and Rider
       IPCR.

8.     Consistent       with   the   stipulation,    EGSI   shall   adjust   depreciation   and
       decommissioning expense related to the River Bend nuclear generating station and
       depreciation expense related to EGSI's steam production assets.

9.     Consistent with the stipulation, EGSI shall submit a new depreciation study.

10.    Consistent with the stipulation, the Rider IPCR and fuel costs, including coal-
       related costs deferred from prior proceedings are reconciled and approved through
       March 31, 2007.

11.    EGSI shall adjust its fuel over/under recovery balance consistent with the findings
       in this order.

12.    The entry of this order consistent with the stipulation does not indicate the
       Commission's endorsement of any principle or methodology that may underlie the
       stipulation. Neither should entry of this order be regarded as precedent as to the
       appropriateness of any principle or methodology underlying the stipulation.

13.    All other motions, requests for entry of specific findings of fact, conclusions of
       law, and ordering paragraphs, and any other requests for general or specific relief,
       if not expressly granted in this order, are hereby denied.
PUC Docket No. 34800                              Order                    Page 15of15
SOAH Docket No. XXX-XX-XXXX




         SIGNED AT AUSTIN, TEXAS the _ _ day of March 2009



                                           PUBLIC UTILITY COMMISSION OF TEXAS



                                                          ~
                                                          /.
                                           B          ITHERMAN, CHAIRMAN




                                           DONNA L. NELSON, COMMISSIONER




 q.\cadm\orders\final\34000\34800fo2.doc
               SOAH DOCKET NO. XXX-XX-XXXX
                 PUC DOCKET NO. 37744




APPLICATION OF ENTERGY TEXAS,           § BEFORE THE STATE OFFICE
INC. FOR AUTHORITY TO CHANGE            §          OF
RATES AND RECONCILE FUEL COSTS          § ADMINISTRATIVE HEARINGS




            DIRECT TESTIMONY AND EXHIBITS

                              OF

                         JACOBPOUS



                       ON BEHALF OF

      CERTAIN CITIES SERVED BY ENTERGY TEXAS, INC.




                         JUNE 9, 2010




               Diversified Utility Consultants Inc.
              1912 West Anderson Lane, Suite 202
                        Austin, TX 78757
 1              between Texas and Louisiana reflected in the storm reserve be retained. This
 2              recommendation reverses the Company's proposed reassignment of costs.
 3
 4   Q.         PLEASE DISCUSS YOUR NEXT ADJUSTMENT TO THE INSURANCE
 5              RESERVE DEFICIT BALANCE.
 6   A.         In association with the securitization process relating to Hurricanes Rita and Katrina, the
 7              Company has received insurance proceeds or has revised its insurance estimates
 8              subsequent to the analysis reflected in Adjustment 15 to the Company's filing. 204 The
 9              Company states there have been two additional changes that impact the insurance related
10              amount reflected in the Company's filing. First, the actual proceeds for Hurricane Katrina
11              received in December 2009 exceeded the estimated proceeds by $7,290. Second, the
12              Company revised the estimated proceeds for Hurricane Rita that exceeded the previous
13              estimate by $1,511,688. 205 Therefore, the combined total of these two insurance proceed
14              related adjustments total $1,518,978 and should be recognized in this case.
15
16   Q.         PLEASE DISCUSS YOUR LAST ADJUSTMENT TO THE INSURANCE
17              RESERVE DEFICIT BALANCE.
18   A.         1 recommend reversal of Company proposed Adjustment 15. This proposed adjustment
19              attempts to remove from the insurance reserve the unrecovered hurricane insurance
20              proceeds, insurance proceeds in excess of insurance proceeds included in the
21              securitization process and carrying costs. 206 ETI proposes to carve $25 million out of the
22              insurance reserve and establish a separate regulatory component for which it also
23              proposes a 5-year amortization. There is no valid basis for this proposed separate and
24              unique treatment. Therefore, ETI's proposed Adjustment 15, Hurricane Securitization,
25              should be eliminated by returning the $25 million amount to the insurance reserve. This
26              recommendation does not impact rate base, but does reduce the net annual amortization
27              by $3,791,732 due to the differing amortization periods (5 years           Adjustment 15
28              versus 20 years for storm insurance reserve).
29

          204
              Response to Rose City 23-21.
          ws Id.
          206
              Testimony of Mr. Wright at page 20.

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