                                                                                     ACCEPTED
                                                                                 03-14-00735-CV
                                                                                         5514728
                                                                      THIRD COURT OF APPEALS
                                                                                 AUSTIN, TEXAS
                                                                             6/2/2015 3:48:59 PM
                                                                               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                 6/2/2015 3:48:59 PM
                                                            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
 ________________________________________________________________

               ENTERGY TEXAS, INC.’S REPLY BRIEF
 _________________________________________________________________

                                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.


June 2015


                   ORAL ARGUMENT REQUESTED
                                         TABLE OF CONTENTS

TABLE OF CONTENTS ........................................................................................... i 

INDEX OF AUTHORITIES..................................................................................... ii 

ARGUMENT AND AUTHORITIES ........................................................................1 

I.       There is no evidence or legal justification for the Commission’s
         disallowance of over $11 million associated with ETI’s unrecovered
         Hurricane Rita reconstruction costs.................................................................1 

         A.       Nothing in PURA required the Commission to address
                  amortization of the regulatory asset in Docket No. 37744. ..................1 

         B.       There is no evidence that anyone intended ETI to begin
                  amortizing the regulatory asset upon the settlement of Docket
                  No. 37744. .............................................................................................3 

II.      The Commission’s refusal to make any adjustment to ETI’s test-year
         level of purchased capacity expense is arbitrary and capricious and
         unsupported by substantial evidence. ..............................................................7 

         A.       The Commission misapplied the standard for adjustments to
                  test-year expenses. .................................................................................8 

         B.       The Commission’s refusal to make any adjustment to test-year
                  levels of capacity costs is not supported by substantial
                  evidence. ..............................................................................................11 

III.     The Commission’s decision to set ETI’s transmission equalization
         expense at the test-year level is unsupported by substantial evidence. .........16 

CONCLUSION AND PRAYER .............................................................................18 

CERTIFICATE OF COMPLIANCE .......................................................................19 

CERTIFICATE OF SERVICE ................................................................................20 

APPENDIX ..............................................................................................................22 




                                                             i
                                   INDEX OF AUTHORITIES

Cases 
AEP Texas Central Co. v. Public Util. Comm’n of Tex.,
  286 S.W.3d 450 (Tex. App. – Corpus Christi 2008, pet. denied) .........................4
Bowden v. Phillips Petroleum Co.,
  247 S.W.3d 690 (Tex. 2008) ..................................................................................8
City of El Paso v. Public Util. Comm’n of Tex.,
  883 S.W.2d 179 (Tex. 1994) ..................................................................................9
Commint Technical Services, Inc. v. Quickel,
 314 S.W.3d 646 (Tex. App. – Houston [14th Dist.] 2010, no pet.) ........................4
Freedom Communications, Inc. v. Coronado,
  372 S.W.3d 621 (Tex. 2012) ..................................................................................5
Hawkins v. Texas Co.,
 209 S.W.2d 338 (Tex. 1948) ................................................................................18
Hendee v. Dewhurst,
 228 S.W.3d 354 (Tex. App. -- Austin 2007, pet. denied) ......................................5
Katy Intern., Inc. v. Jinchun Jiang,
  451 S.W.3d 74 (Tex. App. – Houston [14th Dist.] 2014, pet. requested) .............5
Office of Pub. Util. Counsel v. Public Util. Comm'n,
  878 S.W.2d 598 (Tex. 1994) ..................................................................................5
Office of Pub. Util. Counsel v. Texas-New Mexico Power Co.,
  344 S.W.3d 446 (Tex. App. – Austin 2011, pet. denied) ......................................4
Railroad Comm’n of Tex. v. High Plains Natural Gas Co.,
  628 S.W.2d 753 (Tex. 1981) .................................................................................9
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) .................................4
Suburban Util. Corp. v. Public Util. Comm’n of Tex.,
  652 S.W.2d 358 (Tex. 1983) ....................................................................... 8, 9, 16
Texas Utils. Elec. Co. v. Public Util. Comm’n,
  881 S.W.2d 387 (Tex. App. – Austin 1994),
  rev’d on other grounds, 935 S.W.2d 109 (Tex. 1996) .................................. 15, 18


                                                       ii
Vickers v. State,
  No. 06-14-00072-CR, 2015 WL 1882910, *6 n.11
  (Tex. App. – Texarkana Apr. 27, 2015, no pet. h.) ................................................5
Woods v. William M. Mercer, Inc.,
 769 S.W.2d 515 (Tex. 1988) ..................................................................................4
Statutes 
Tex. Gov’t Code Ann. § 2001.174...................................................................... 8, 18
Tex. Util. Code Ann. § 11.001, et seq. ......................................................................1
Tex. Util. Code Ann. § 11.002 .................................................................................10
Tex. Util. Code Ann. § 36.051 ...................................................................................9
Tex. Util. Code Ann. § 39.459 ...............................................................................2, 3
Tex. Util. Code Ann. § 39.462 ...............................................................................2, 3
Rules 
16 Tex. Admin. Code § 25.231 ........................................................................... 9, 10
Tex. R. Civ. P. 94 .......................................................................................................4
Tex. R. Evid. 201 .......................................................................................................5
Administrative	Cases 
Application of Entergy Gulf States, Inc. for Determination of
  Hurricane Reconstruction Costs, Docket No. 32907.............................................7
Application of Entergy Texas, Inc. for Authority to Change Rates and
  Reconcile Fuel Costs, Docket No. 37744 .........................................................5, 6




                                                            iii
       Appellant Entergy Texas, Inc. (“ETI”) respectfully submits this reply to the

appellees’ briefs of the Public Utility Commission of Texas (“the Commission” or

“PUCT”) and Texas Industrial Energy Consumers (“TIEC”).

                         ARGUMENT AND AUTHORITIES

I.     There is no evidence or legal justification for the Commission’s
       disallowance of over $11 million associated with ETI’s unrecovered
       Hurricane Rita reconstruction costs.

       ETI challenges the Commission’s decision to allow it to amortize only $15

million of its Hurricane Rita regulatory asset. That is about $11 million less than

ETI proved it is entitled to but has not recovered. The Commission, the only party

to address this issue in its response brief, does not present any persuasive argument

for upholding its decision.

       A.     Nothing in PURA1 required the Commission to address
              amortization of the regulatory asset in Docket No. 37744.

       One of the rationales the Commission gave in support of its decision was its

view that PURA section 39.459(c) required ETI’s unrecovered Hurricane Rita

reconstruction costs to be addressed in a previous case, Docket No. 37744.2 As

explained in ETI’s appellant’s brief, section 39.459(c) does not apply to the

situation at hand. That provision addresses what should happen when a utility

securitizes hurricane reconstruction costs and then recovers them a second time

1
 See Tex. Util. Code Ann. § 11.001, et seq. (“Public Utility Regulatory Act” or “PURA”).
2
 AR Part I, Binder 5, Item 185 (Proposal for Decision at 15 & 21-22); AR Part I, Binder 7, Item
244 (Order on Rehearing at 1).
                                              1
from an insurance company. See Tex. Util. Code Ann. § 39.459(c). Here, neither

of those things happened. A different statute, PURA section 39.462(a), applies in

this situation. That provision authorizes a utility to seek unrecovered hurricane

reconstruction costs “in its next base rate proceeding or through any other

proceeding authorized by Subchapter C, Chapter 36.” Id. § 39.462(a) (emphasis

added). It is undisputed that this case is authorized by Chapter 36.

         The Commission now tacitly acknowledges that section 39.462(a) applies,

but still argues that the issue was statutorily required to be addressed in Docket No.

37744.3 The Commission contends that even under section 39.462(a), it was

required to address the issue in Docket No. 37744 because that was the “next”

base-rate proceeding after ETI knew it would not receive the anticipated insurance

proceeds.4 That statute says no such thing. Indeed, section 39.462(a) broadly

authorizes the Commission to address the issue in “any” proceeding authorized by

Chapter 36. This reflects the legislature’s understanding of the fact that it is often

difficult or impossible for a utility to know when multiple, large insurance claims

or government grants will be paid in full. Under the plain language of PURA

section 39.462(a), the Commission had authority to address the issue in this case.

         Moreover, the Commission is flat wrong that Docket No. 37744 was the first

base rate case after ETI “knew” what insurance proceeds it would recover. It is

3
    PUCT’s Appellee’s Brief at 16-17.
4
    See id. at 18.
                                          2
true that ETI had not recovered these insurance proceeds when it initiated Docket

No. 37744. But it is undisputed that ETI ended up receiving another $5 million in

insurance proceeds after Docket No. 37744, and ETI adjusted its regulatory asset

to account for this fact.5      Even under the Commission’s erroneous interpretation

of PURA sections 39.459(c) and 39.462(a), then, the Commission was not limited

to addressing the issue of hurricane reconstruction costs in Docket No. 37744.

       B.      There is no evidence that anyone intended ETI to begin
               amortizing the regulatory asset upon the settlement of
               Docket No. 37744.

       The second rationale the Commission gave for its order was its conclusion

that ETI did not disprove that the issue was resolved in Docket No. 37744.6 That

was not, however, ETI’s burden. ETI affirmatively established that it had not yet

included the unrecovered insurance proceeds in its rate base, or begun recovering

them, when it filed this case.7 Intervening parties responded by arguing that ETI

should already have either written off or begun amortizing the Hurricane Rita

regulatory asset upon the conclusion of Docket No. 37744.8 In other words,

intervenors argued that Docket No. 37744 barred ETI from seeking permission to

amortize the full amount of the asset in this rate case. Intervenors, not ETI, bore


5
  AR Part II, Binder 37, ETI Exh. 46 (Considine Rebuttal at 18 of 55).
6
  AR Part I, Binder 5, Item 185 (Proposal for Decision at 22); AR Part I, Binder 7, Item 244
(Order on Rehearing at 1).
7
  AR Part II, Binder 32, ETI Exh. 8 (Considine Direct at 20).
8
  E.g., AR Part II, Binder 40, Staff Exh. 1 (Givens Direct at 32-35); AR Part II, Binder 8, Cities
Exh. 2 (Garrett Direct at 11).
                                                3
the burden of proof on this affirmative defense. E.g., Tex. R. Civ. P. 94; Woods v.

William M. Mercer, Inc., 769 S.W.2d 515, 517 (Tex. 1988); Commint Technical

Services, Inc. v. Quickel, 314 S.W.3d 646, 651 (Tex. App. – Houston [14th Dist.]

2010, no pet.).

      Regardless of who bore the burden of proof, the Commission is bound to

interpret a settlement and an order adopting it in accordance with the rules of

contract interpretation. See AEP Texas Central Co. v. Public Util. Comm’n of Tex.,

286 S.W.3d 450, 464 (Tex. App. – Corpus Christi 2008, pet. denied).              The

Commission cannot use the opportunity to interpret its prior order as a means to

amend it. E.g., Office of Public Util. Counsel v. Texas-New Mexico Power Co.,

344 S.W.3d 446, 452 (Tex. App. – Austin 2011, pet. denied). Under the rules of

contract interpretation, the primary duty of the Commission is to determine and

give effect to the parties’ intentions as expressed in the document. AEP Tex. Cent.

Co., 286 S.W.3d at 464.

      The Docket No. 37744 order does not say anything about the Hurricane Rita

regulatory asset, and the Commission does not pretend that it does. Nor does the

Commission dispute that a utility must have a regulator’s authority to begin

recovering a regulatory asset. See, e.g., 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) (recovery of regulatory asset is two-step process, the

                                         4
second step being the authorization of a recovery mechanism). The Commission

nevertheless argues that the amortization of the Hurricane Rita regulatory asset

should have been “considered” approved in Docket No. 37744 because the order in

that case was “ambiguous,” and there is substantial evidence that no one in that

case disputed that ETI should get to recover the regulatory asset.

       The Commission is correct that there is evidence in this case that no one in

Docket No. 37744 contested ETI’s right to recover the Hurricane Rita regulatory

asset at some point in time. However, there was a dispute in Docket No. 37744

about when and how ETI could recover the regulatory asset. Cities’ witness Jacob

Pous testified in Docket No. 37744 that ETI should not be able to amortize the

regulatory asset over a five-year period, and should credit the amount to its storm

reserve instead.9 No witness in this case testified about, much less controverted,

that fact. In short, no witness to this case said the parties to Docket No. 37744

agreed that ETI should begin amortizing the regulatory asset when the case was


9
  See Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs,
Docket No. 37744 (Pous Direct at 113). A certified copy of Mr. Pous’s testimony is attached to
this brief at Appendix A. ETI does not present this document in support of the truth of its
content. ETI presents the document only to establish that it was filed, and the nature of the
matter the witness discussed, in the prior docket. This document was filed with the Commission,
a state agency. It is publicly available, and its authenticity is readily verifiable. This Court can,
therefore, take judicial notice of the document for the limited purpose ETI presents it. Tex. R.
Evid. 201(b); Freedom Communications, Inc. v. Coronado, 372 S.W.3d 621, 623 (Tex. 2012);
Office of Pub. Util. Counsel v. Public Util. Comm'n, 878 S.W.2d 598, 600 (Tex. 1994); Vickers
v. State, No. 06-14-00072-CR, 2015 WL 1882910, *6 n.11 (Tex. App. – Texarkana Apr. 27,
2015, no pet. h.); Katy Intern., Inc. v. Jinchun Jiang, 451 S.W.3d 74, 94 n.20 (Tex. App. –
Houston [14th Dist.] 2014, pet. requested); Hendee v. Dewhurst, 228 S.W.3d 354, 377 n.30 (Tex.
App. -- Austin 2007, pet. denied).
                                                 5
settled. Nevertheless, the Commission concluded in this case that ETI should have

done that. There is no testimony supporting the Commission’s conclusion.

       The only evidence in this case of what the parties intended when they settled

Docket No. 37744 is the settlement agreement itself.              Though the settlement

agreement expressly mentioned several issues in the case, it said nothing about

ETI’s request to amortize the Hurricane Rita regulatory asset. The agreement

certainly gave no indication that the parties intended ETI to begin recovering the

regulatory asset immediately. The agreement did, however, say, “[e]xcept to the

extent that the Stipulation expressly governs a Signatory’s rights and obligations

for future periods, this Stipulation shall not be binding or precedential upon a

Signatory outside this docket, and Signatories retain their rights to pursue relief to

which they may be entitled in other proceedings.”10

       Despite that language in the agreement, the Commission maintains that the

Mother Hubbard clause in the order adopting the settlement supports its decision in

this case.11 The order says that “any … requests for general or specific relief, if not

expressly granted in this order, are hereby denied.”12 It is undisputed that neither



10
   Id. (Aug. 6, 2010 Stipulation and Settlement Agreement at 12) (emphasis added).
11
   PUCT’s Appellee’s Brief at 21.
12
   Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs,
Docket No. 37744 (Dec. 13, 2010, Order at ¶ 15). Public filings in Commission dockets may be
accessed at the Commission’s interchange:
  http://interchange.puc.texas.gov/WebApp/Interchange/application/dbapps/filings/pgSearch.asp
The “Control Number” for each case is its docket number.
                                             6
the settlement agreement nor the order expressly granted ETI the authority to begin

amortizing the Hurricane Rita regulatory asset.13

       In light of this language in the Docket No. 37744 order and the fact that

recovery of a regulatory asset requires express agency approval, it would have

been unreasonable for ETI to begin amortizing the asset upon the conclusion of

Docket No. 37744. The factual basis for the Commission’s contrary conclusion in

this case is not supported by substantial evidence.                  And there is no legal

justification – articulated in the Commission’s order or not – supporting what the

Commission did here.          Because there is no evidence or law supporting the

Commission’s decision, it is not entitled to any deference and should be reversed.

II.    The Commission’s refusal to make any adjustment to ETI’s test-year
       level of purchased capacity expense is arbitrary and capricious and
       unsupported by substantial evidence.

       In its initial brief, ETI challenged the Commission’s refusal to include in

rates any of the increase in purchased capacity expense ETI proved it would incur

by the time rates went into effect. Neither the Commission nor TIEC presents any

13
   The Attorney General makes a cryptic argument on page 21 of its brief, suggesting that ETI
cannot logically argue that “only one part of its request could have been approved” in Docket
No. 37744. See PUCT’s Appellee’s Brief at 21. ETI does not contend that the Commission
approved anything regarding the Hurricane Rita regulatory asset in Docket No. 37744. The
Commission approved ETI’s creation of the regulatory asset in Docket No. 32907 when it
recognized ETI’s future right to true-up its anticipated insurance recovery. See Application of
Entergy Gulf States, Inc. for Determination of Hurricane Reconstruction Costs, Docket No.
32907 (Dec. 1, 2006, Order at FOF 28). ETI sought approval of a recovery mechanism in
Docket No. 37744. ETI’s point here is that the Commission did not even mention the Hurricane
Rita regulatory asset, much less approve an amortization schedule for the asset, in its Docket No.
37744 order.
                                                7
logical basis upon which to disallow the entire $30 million increase in expenses at

issue.

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

         The Commission took the view that only ETI’s test-year level of purchased

capacity expense should be included in rates because acknowledging known and

measurable changes to test-year data is an “exception.”14 ETI challenged that view

as contrary to PURA and judicial precedent.

         In response, the Commission and TIEC point out that the Commission may

exercise “discretion” in determining what changes to make to test-year levels of

expense. That does not mean, however, that the Commission has carte blanche to

do whatever it wants. Even when it exercises discretion, the Commission must

adhere to some guiding principles. See, e.g., Tex. Gov’t Code Ann. § 2001.174(2)

(agency order reversible for abuse of discretion); Bowden v. Phillips Petroleum

Co., 247 S.W.3d 690, 696 (Tex. 2008) (failure to adhere to any guiding principles

constitutes abuse of discretion).

         One of those principles is that rates are set prospectively. E.g., Suburban

Util. Corp. v. Public Util. Comm’n of Tex., 652 S.W.2d 358, 366 (Tex. 1983).

Another is that a utility is entitled to a reasonable opportunity to recover all of the


14
   AR Part I, Binder 7, Item 244 (Order on Rehearing at 1); AR Part I, Binder 5, Item 185
(Proposal for Decision at 108).
                                           8
reasonable and necessary expenses it incurs when the rates are in effect. See Tex.

Util. Code Ann. § 36.051; Railroad Comm’n of Tex. v. High Plains Natural Gas

Co., 628 S.W.2d 753 (Tex. 1981). PURA provides no support for giving test-year

data more weight than rate-year data in the process of setting rates. PURA does

not even impose the test-year construct – that is a Commission-made ratemaking

convention. Compare Tex. Util. Code Ann. § 36.051 with 16 Tex. Admin. Code

§ 25.231(a). And the Texas Supreme Court has acknowledged that the goal of the

process is to make the test-year data as representative as possible of the cost

situation that is apt to prevail in the future, not the past. City of El Paso v. Public

Util. Comm’n of Tex., 883 S.W.2d 179, 188 (Tex. 1994). Costs that can be

anticipated with reasonable (not absolute) certainty should be included.           See

Suburban Util. Corp., 652 S.W.2d at 362.

      TIEC and the Commission acknowledge this is the standard. But they argue

the Commission’s order should be upheld because ETI could not predict its rate-

year costs with surgical precision. That cannot be a basis upon which to disallow

the entire adjustment. Without a crystal ball, it is impossible to know future costs

to the dollar.    The Commission may not disregard compelling evidence of

substantial increases to test-year levels of expense simply because there may be

some level of uncertainty at the margin.




                                           9
       TIEC argues that projections of future expenses should be treated as

inherently suspect because there is a risk the projections will end up being too

high. TIEC fails to note that placing undue emphasis on test-year data imposes the

opposite risk – that rates will end up being too low. The Commission is charged

with setting rates that are just and reasonable for both consumers and utilities.

Tex. Util. Code Ann. § 11.002(a).

       Contrary to TIEC’s assertions, ETI does not, in this appeal, seek to overturn

the Commission’s test-year approach to ratemaking. See 16 Tex. Admin. Code

§ 25.231(a). ETI simply seeks to hold the Commission to PURA’s basic guarantee

to utilities. To give effect to that guarantee, historical test-year data can only be

the starting place for setting rates. Because rates are set on a prospective basis,

evidence of known and measurable changes to test-year data must be given at least

equal weight to the test-year data itself.            It cannot logically be treated with

suspicion or as an “exception” that is subject to a heightened proof requirement.

       The Commission itself acknowledges this principle in other contexts. The

Commission made adjustments to other categories of ETI’s test-year expense, even

though those adjustments were based upon projections and estimates.15 If the

Commission is to allow post-test-year changes based upon projections in one



15
  E.g., AR Part I, Binder 5, Item 185 (Proposal for Decision at 68 (short-term asset update), 163-
64 (payroll adjustments), & 182-86 (ad valorem tax rate update)).
                                               10
situation, it must allow them in another. It is an abuse of discretion to apply

different standards in materially analogous circumstances.

       B.     The Commission’s refusal to make any adjustment to test-
              year levels of capacity costs is not supported by substantial
              evidence.

       ETI showed that during the time rates would be in effect, it would incur over

$38 million annually above its test-year level of purchased capacity expense. ETI

showed that by procuring these third-party resources, it would save about $8

million annually in payments related to Entergy system resources. Accordingly,

ETI requested the Commission to include the net $30 million increase over its test-

year levels of purchased capacity expense in rates.

       The Commission and TIEC argue the Commission was justified in denying

this request for several reasons. First, the Commission says ETI merely “believes”

its contracts will be in place during the rate year.16 But ETI proved that all the

third-party capacity contracts were executed before the hearing.17 Indeed, one of

them went into effect during the test year,18 and another went into effect five

months after the test-year end and several months before the hearing in this case.19




16
   See PUCT’s Appellee’s Brief at 33.
17
   E.g., AR Part IV, Binder 43, Vol. L (5/3/12 Tr. at 1942 & 1959) (Frontier contract); AR Part
II, Binder 35, ETI Exh. 34 (Cooper Direct at 17 of 25) (SRMPA contract); AR Part II, Binder 35,
ETI Exh. 34 (Cooper Direct at 16 of 25) (regarding Calpine contract).
18
   AR Part IV, Binder 43, Vol. L (5/3/12 Tr. at 1942 & 1959) (regarding Frontier contract).
19
   AR Part II, Binder 35, ETI Exh. 34 (Cooper Direct at 17 of 25) (regarding SRMPA contract).
                                              11
       The Commission and TIEC also argue that ETI simply “assumed” it would

have to pay for all the third-party resources it had contracted for.               That is

affirmatively debunked by the record. ETI’s expectation that any adjustments for

poor performance under the Frontier contract would be minor was based upon its

past experience with the Frontier resource.20 ETI also proved that its agreement

with SRMPA was for “system capacity.”21 Even if one of SRMPA’s resources

were to falter, there is no evidence supporting the conclusion that SRMPA’s entire

system might become unavailable. ETI further proved that it had experience with

the Calpine resource, and that price deviations under that contract were “very, very

small” in ETI’s experience.22 ETI took its historical experience into account when

projecting future costs, and did not blindly assume what they would be under these

contracts.

       The Commission and TIEC also contend that there are multiple “offsets”

that would negate any additional expense ETI will incur under the new third-party

purchased capacity contracts. As ETI pointed out in its appellant’s brief, none of

these offsets justifies a complete disallowance of ETI’s entire capital outlay for the

contracts at issue.




20
   AR Part IV, Binder 43, Vol. F (4/26/12 Tr. at 705).
21
   AR Part II, Binder 31, ETI Exh. 3A (SRMPA Power Contract) [Highly Sensitive].
22
   AR Part IV, Binder 42, Vol. L (5/3/12 Tr. at 1942).
                                            12
       Both the Commission and TIEC contend that future load growth may offset

some of ETI’s increased purchased capacity expense. Even if the Commission

could properly consider future load growth in setting base rates, ETI made the

additional third-party capacity purchases to serve existing load,23 and existing

customers would recoup substantial savings from increased efficiencies and fuel

savings that would result from the purchases.24             Moreover, intervenors’ load

growth projections would not fully materialize until the rate year,25 but ETI began

incurring the additional purchased capacity costs during and shortly after the test

year. The prospect of load growth in ETI’s service area cannot logically offset the

immediate increase in purchased capacity expense at issue.

       The Commission and TIEC also attempt to cast doubt upon ETI’s evidence

about how much the increased third-party capacity purchases enable ETI to avoid

in MSS-1 costs.26 But TIEC’s own witness admitted the inverse relationship

between the two categories of cost.27 Indeed, the record establishes that MSS-1

costs reached test-year lows during the last two months of the test year, when the



23
   AR Part II, Binder 37 (ETI Exh. 47, Cooper Rebuttal at 5-7); see also AR Part II, Binder 37
(ETI Exh. 57, May Rebuttal at 13-15).
24
   AR Part II, Binder 35 (ETI Exh. 34, Cooper Direct at 24 of 25).
25
   AR Part IV, Binder 43, Vol. J (5/1/12 Tr. at 1299-1300) [Highly Sensitive].
26
   As explained in ETI’s appellant’s brief, Schedule MSS-1 to the Entergy System Agreement
requires the various Entergy operating companies to make and receive payments according to
their relative share of total system capacity. See AR Part II, Binder 37, ETI Exh. 47 (Cooper
Rebuttal at 5-6).
27
   AR Part II, Binder 41, TIEC Exh. 1 (Pollock Direct at 22, Table 1).
                                             13
Frontier contract was stepped up.28 And another intervenor, Cities, adopted ETI’s

calculation of rate-year MSS-1 costs.29

       Finally, the MSS-430 calculation is not a basis upon which to disallow all of

ETI’s increased third-party purchased capacity costs.             The Commission itself

acknowledged that, save for costs associated with ETI’s contract with its Arkansas

affiliate, MSS-4 costs would remain “fairly stable” from the test year to the rate

year.31 Regarding the Arkansas contract (referred to by the parties as the Entergy

Arkansas, “EAI” or “EA” “WBL” contract), Cities’ and TIEC’s proposed

adjustments are not reasonably supported by the record. The evidence shows that

although the contract expired after the test year, ETI had extended the contract by

the time the hearing took place.32 Additionally, it is not reasonable to conclude

that if the Arkansas contract were not in place, ETI would not replace it with

another resource, since it is undisputed that ETI needed the capacity.33

       In a nutshell, the Commission and TIEC argue that because there is “some

uncertainty” in these projections, it was inappropriate to make any adjustment. But


28
   See AR Part II, Binder 9, Cities Exh. 6C (Nalepa Direct Attachment KJN-3 at 2) [Highly
Sensitive].
29
   AR Part II, Binder 9, Cities Exh. 6C (Nalepa Direct at 17 [Highly Sensitive]).
30
    As explained in ETI’s initial brief, Schedule MSS-4 to the Entergy System Agreement
contains a formula that sets the price of power purchased from specific units owned by other
Entergy operating companies. See AR Part II, Binder 36, ETI Exh. 39 (Cicio Direct at 24-26).
31
   AR Part I, Binder 5, Item 185 (Proposal for Decision at 100); AR Part I, Binder 7, Item 244
(Order on Rehearing at 1).
32
   AR Part IV, Binder 43, Vol. E (4/26/12 Tr. at 687-88 [Confidential]) .
33
   See AR Part II, Binder 37 (ETI Exh. 47, Cooper Rebuttal at 15-16 of 21).
                                             14
this Court long ago rejected the notion that when some of a utility’s proposal is

challenged, the entire proposal must be rejected unless the utility itself quantifies

the challenged piece. See Texas Utils. Elec. Co. v. Public Util. Comm’n, 881

S.W.2d 387, 404 (Tex. App. – Austin 1994), rev’d on other grounds, 935 S.W.2d

109 (Tex. 1996). This Court recognized that when the evidence conflicts about

how much of a proposal to include, it is the Commission’s job to sift through the

evidence and make the call. The Commission may not just throw its hands in the

air and refuse to address the issue simply because the utility’s evidence is contested

or because the issues are complex. See id. at 404-05.

          TIEC cites the testimony of witnesses who recommended that the

Commission adopt a level of purchased capacity expense below the test-year level,

and suggests this testimony alone supports the Commission’s decision.34 But each

piece of testimony TIEC cites is based upon multiple “offsets” to ETI’s increased

level of expense. Each of these proposed offsets are flawed, as explained in ETI’s

appellant’s brief and above. Moreover, even assuming arguendo one of the offsets

were sustainable, no single offset justifies the entire disallowance. For both these

reasons, it is not reasonable to conclude from the evidence in this record that none

of ETI’s $30 million increase in third-party capacity costs were known and

measurable. The Commission did not even suggest that any single finding justifies


34
     See TIEC’s Appellee’s Brief at 33.
                                          15
the entire disallowance, or how much of the disallowance is attributed to each of its

findings.   Therefore, if this Court determines that any of the Commission’s

findings are unsupported by substantial evidence, it must reverse the whole

disallowance and remand to the Commission for further consideration.

III.   The Commission’s decision to set ETI’s transmission equalization
       expense at the test-year level is unsupported by substantial evidence.

       ETI challenges the Commission’s decision to set ETI’s MSS-2 (that is,

transmission equalization) expense at the test-year level for two reasons. First, the

Commission misapplied the “known and measurable” ratemaking standard, as it

did in setting ETI’s purchased capacity costs. Second, the Commission’s decision

is not supported by substantial evidence.         The Commission and TIEC filed

responses. They devote their entire argument on this issue to attacking ETI’s

evidence supporting its request to include its rate-year level, rather than test-year

level, of MSS-2 expense in rates.

       The issue before the Court, however, is whether there is substantial evidence

supporting the Commission’s conclusion that the test-year MSS-2 expense was the

level the utility “anticipated with reasonable certainty.” Suburban Util. Corp., 652

S.W.2d at 362. Clearly, this is not the case; there is no evidence that the test year

level allowed by the Commission is adequate or representative of the expense the

utility will incur when rates are in effect. All the evidence is to the contrary.



                                           16
       As ETI noted in its initial brief, no witness testified that the test-year level of

expense was a fair or reasonable representation of what ETI would incur under

Schedule MSS-2 when these rates would be in effect. Though they proposed

different levels of increase, every witness testifying on this issue – including ETI’s,

TIEC’s, and Cities’ – recognized that the test-year amount of MSS-2 expense was

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

information. 35 Moreover, ETI established that the actual, historical level of MSS-2

expense it incurred, in every month from the end of the test year to the time of the

hearing, pointed to a substantially increasing, known and measurable level of

expense. 36 TIEC now wholly ignores its own witness’s testimony on this issue,

choosing instead to focus exclusively on its criticisms of ETI’s evidence. Even

assuming arguendo that there is reasonable disagreement about ETI’s proposed

rate-year level of MSS-2 expense, the record conclusively establishes that the test-

year level is not adequate. In this circumstance, the Commission may not blindly

adhere to its test-year convention. There is literally no evidence to support the

Commission’s decision.

       The Commission is bound to consider all the record evidence and reach a

conclusion that is reasonably supported by it. See Hawkins v. Texas Co., 209
35
   AR Part IV, Binder 43, Vol. C (4/25/12 Tr. at 452-53); AR Part IV, Binder 43, Vol. F (4/27/12
Tr. at 738, 760, 763, 780, & 783-84); AR Part II, Binder 41, TIEC Exh. 1 (Pollock Direct at 32-
33); AR Part II, Binder 8, Cities Exh. 4B (Goins Direct, Errata No. 3 at 9 [Highly Sensitive]);
AR Part II, Binder 8, Cities Exh. 4 (Goins Direct at 22).
36
   AR Part II, Binder 9, Cities Exh. 29 (Response of ETI to Cities RFI-5-1).
                                              17
S.W.2d 338, 339-40 (Tex. 1948); Texas Utils. Elec. Co., 881 S.W.2d at 404. The

APA confirms this principle, requiring a court to reverse the agency if its decision

is “not reasonably supported by substantial evidence considering the reliable and

probative evidence in the record as a whole.”               Tex. Gov’t Code Ann.

§ 2001.174(2)(E) (emphasis added). Because the Commission’s decision is not

supported by any evidence, much less reasonably supported by the evidence, the

Court must reverse it.

                          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

Court’s decision. Entergy Texas, Inc. further requests its costs of court and any

other relief to which it may show itself justly entitled.




                                           18
                               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 4,727 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




                                       19
                               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 2nd day of June, 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)37
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




37
     State Agencies have not yet appeared or designated a new lead counsel in this appeal.
                                                 20
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




                                         21
                                APPENDIX

A.   Certified copy of Direct Testimony of J. Pous in PUCT Docket No. 37744




                                     22
APPENDIX A
                   SOAH DOCKET NO. XXX-XX-XXXX
                     PUC DOCKET NO. 37744

'I                                                                                                  II




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


Ii



                 DIRECT TESTIMONY AND EXIDBITS

                                  OF

                             JACOBPOUS



                           ON BEHALF OF
                                                                                                    I

          CERTAIN CITIES SERVED BY ENTERGY TEXAS, INC.




                                                     CBRTIPIBD TO BS ATRUE AND CORRSCT
                                                     COPY OF THE OIUOINAL ON FH..E WITH THE
                                                     PUBLIC UTILITY COMMISSION OF TEXAS
                             JUNE9,2010
                                                     c~~'~.

                                                     :*t:3';•
                   Diversified Utility Consultants Inc.
                  1912 West Anderson Lane, Suite 202
                            Austin, TX 78757
                                                            Record copY
                                                                                                ·-
                                                                  UL \ 3 'l.0\6
                                               Cities Exhibit ,       'K.'f
                                                                                              ·-·
,I   '
                                                              TABLE OF CONTENTS


    SECTION I:               INTRODUCTION .................................................................................................... 1

    SECTION II:              DEPRECIATION ..................................................................................................... 7

       1. General ........................................................................................................................................ 7

      2. Production Life ........................................................................................................................... 11

          A. General ................................................................................................................................... 11

          B. Basis for Retirement Dates ..................................................................................................... 14

          C. Recommendation .................................................................................................................... 21

      3. Production Interim Retirements .................................................................................................. 22

      4. Production Net Salvage ............................................................................................................... 26

          5. Mass Property Life .................................................................................................................. 38

          A. Introduction ........................................................................................................................... 38

          B. Account Specific Adjustments .............................................................................................. 43

      6. Mass Property Net Salvage ......................................................................................................... 71

      7. ELG vs. ALG Calculation Procedure ......................................................................................... 76

      8. Remaining Life Method .............................................................................................................. 86

    SECTION III:             FULLY ACCRUED DEPRECIATION ................................................................. 89

    SECTION IV:              SGSF CAPITAL RECOVERY .............................................................................. 93

    SECTIONV:                STORM INSURANCE RESERVE ...................................................................... 102

       1. General .................................................................................................................................... I 02

      2. Storm Reserve Deficit ............................................................................................................. 105

      3. Target Reserve ........................................................................................................................ 114

      4. Annual Expected Losses ......................................................................................................... 117

I     5. Minimum Storm Reserve Threshold ....................................................................................... 120

    SECTION VI: CASH WORKING CAPITAL ................................................................................. 123
I                                                                                                                                                         I
  1. Introduction ............................................................................................................................. 123

  2. General .................................................................................................................................... 125

  3. Revenue Lag ............................................................................................................................. 127

     A. Meter Reading To Billing ................................................................................................... 127

     B. Billing-To-Payment Revenue Lag ...................................................................................... 130

     C. Customer Float .................................................................................................................... 135

  4. Expense Leads .......................................................................................................................... 136

     A. Payroll .................................................................................................................................. 136

     B. FAS 106 .............................................................................................................................. 139

     C. Entergy Services Inc. ("ESI") Expense Lead ..................................................................... 141

     D. Other O&M Expense Lead ................................................................................................. 142

SECTION VII:            RIVER BEND DECOMMISSIONING REVENUE REQUIREMENT .............. 144

SECTION VIII: RIVER BEND DEPRECIATION RATES ........................................................... 149




                                                                                                                                                    2
                                   ACRONYMS:


2008 Study   2008 Gannett Fleming Depreciation Study
AICPA        American Institute of Certified Public Accountants
ALG          Average Life Group
APFD         Accumulated Provision for Depreciation
ASL          Average Service Life
CIS          Consumer Information Systems
Company      Entergy Texas, Inc.
Commission   Public Utility Commission of Texas
CPI          Consumer Price Index
ewe          Cash Working Capital
DUCI         Diversified Utility Consultants, Inc
EIA          U.S. Energy Information Administration
EAi          Entergy Arkansas, Inc.
EGSL         Entergy Gulf States Louisiana
ELG          Equal Life Group
ESI          Entergy Services, Inc.
ETI          Entergy Texas, Inc.
FERC         Federal Energy Regulatory Commission
FPL          Florida Power & Light Company
FPSC         Florida Public Service Commission
MPSC         Michigan Public Service Commission
NARUC        National Association of Regulatory Utility Commissioners
NIMB         "not in my backyard" syndrome
NPC          Nevada Power Company
NPSC         Nevada Public Service Commission
NRC          Nuclear Regulatory Commission
O&M          Operation & Maintenance
occ          Oklahoma Corporation Commission
OLT          Observed Life Table
PSO          Public Service of Oklahoma
PUC          Public Utility Commission of Texas
RCT          Railroad Commission of Texas

                                                                        1
Reserve   Accumulated Provision for Depreciation
SGSF      Spindletop Gas Storage Facility
SGT       Sabine Gas Transportation Company
SRP       Strategic Resource Plan
SWEPCO    Southwest Electric Power Company
USOA      FERC Uniform System of Accounts




                                                   2
                                              Docket No. 37744


         APPLICATION OF ENTERGY TEXAS                    §             BEFORE THE
         INC. FOR AUTHORITY TO CHANGE                    §           PUBLIC UTILITY
         RATES & RECONCILE FUEL COSTS                    §      COMMISSION OF TEXAS




         SECTION I: INTRODUCTION


     1   Q.   PLEASE STATE YOUR NAME AND BUSINESS?
     2   A.   My name is Jacob Pous and my business address is 1912 W. Anderson Lane, Suite 202,
     3        Austin, Texas 78757.
     4
     5   Q.   WHAT IS YOUR OCCUPATION?
     6   A.   I am a principal in the firm of Diversified Utility Consultants, Inc. ("DUCI"). A copy of
     7        my qualifications appears as Appendix A.
     8
     9   Q.   HAVE YOU PREVIOUSLY TESTIFIED IN PUBLIC UTILITY PROCEEDINGS?
    10   A.   Yes. Appendix A also includes a list of proceedings in which I have previously presented
    11        testimony. In addition, I have been involved in numerous utility rate proceedings that
    12        resulted in settlements before testimony was filed. In total, I have participated in well
    13        over 400 utility rate proceedings in the United States and Canada.
    14
    15   Q.   WHAT IS YOUR PROFESSIONAL BACKGROUND?
    16   A.   I am a registered professional engineer. I am registered to practice as a Professional
    17        Engineer in the State of Texas, as well as numerous other states.
    18
    19   Q.   ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING?
    20   A.   I am testifying on behalf of the cities of Anahuac, Beaumont, Bridge City, Cleveland,
    21        Conroe, Houston, Huntsville, Montgomery, Navasota, Oak Ridge North, Pine Forest,
    22        Pinehurst, Port Arthur, Port Neches, Groves, Nederland, Orange, Rose City, Shenandoah,

I                                                                                                     1

I
 1        Silsbee, Sour Lake, Splendora, Vidor, and West Orange ("Cities") served by the Entergy
2         Texas, Inc. ("Company" or "ETI").
 3
4    Q.   WHAT IS THE PURPOSE OF YOUR TESTIMONY?
 5   A.   The purpose of my testimony is to address certain adjustments that are required to ETI's
 6        requested rate increase filed before the Public Utility Commission of Texas
 7        ("Commission" or "PUC"). I have provided Cities' witness Mr. Garrett with my
 8        recommendations in order that they will be incorporated into the Cities' total revenue
 9        requirement presentation.
10
11   Q.   PLEASE BRIEFLY SUMMARIZE YOUR TESTIMONY.
12   A.   The following is a brief summary of each of the major areas I address herein.
13
14           •   Production Plant Life Spans. The Company proposes to retire almost all of its
15               gas-fired generation on June 30, 2025, for purposes of calculating depreciation
16               rates in this case as set forth in the 2008 Gannett Fleming depreciation study
17               ("2008 Study"). The proposed retirement year is earlier than and inconsistent with
18               the Company's internal planning for system resources. The Company's proposed
19               depreciation life spans assumes a retirement date that is also artificially short in
20               comparison to the life expectancy by the industry as well as the Company's own
21               resource planning division. I recommend establishing minimum life spans for the
22               Company's gas-fired generating facilities at the later of the year 2029 or when
23               such units reach 65 years of age. The standalone impact of this recommendation is
24               a reduction in depreciation expense of $11. 7 million based on plant in service as
25               of December 31, 2008.
26
27           •   Interim Retirements. In spite of this Commission's previous rulings and
28               precedent regarding exclusion of interim retirements in the calculation of
29               production plant depreciation rates, the Company still proposes interim
30               retirements in its calculation. The Company's witness, Mr. Spanos attempts to
31               distinguish the Commission precedent by relying on an incorrect premise that the
32               Company's interim retirement analysis is based on a historical perspective, and
33               the Commission's precedent is applicable to a future perspective. This is a
34               distinction without a difference, because the Company applies the result of its
35               historical calculations to projected future results. Therefore, the Company's
36               witness's attempt to distinguish the Company's request from previous
37               Commission decisions is incorrect. The impact of upholding the Commission's
38               long standing precedent against interim retirements results in an approximate $4.6
39               million reduction in depreciation expense based on plant as of December 31,
40               2008.

                                                                                                   2
     1
     2   •   Production Plant Net Salvage. The Company proposes negative net salvage
     3       values ranging from a negative 15% to a negative 32% for its gas and coal-fired
     4       generations. The Company's coal-fired proposal isbased on an undocumented,
     5       unsupported and inappropriate regression analysis associated with a database for
     6       which the Company's depreciation witness has no first-hand knowledge. The
     7       Company does not have a regression or any mathematical model to estimate net
     8       salvage for gas-fired generation, but rather assumes it is approximately 80% of
     9       the coal-fired value. Therefore, assuming the 80% factor to be correct, any
    10       inaccuracies in the coal regression analysis would carry over to the Company's
    11       projected net salvage for gas-fired generation. As a second step to the Company's
    12       unsupported net salvage analysis, Mr. Spanos escalates the estimated demolition
    13       costs as of the end of 2008 into the future for as many as 35 years and
    14       recommends s that current customers pay with current dollars for future inflated
    15       costs. These aspects of the Company's analysis are neither credible nor
    16       reasonable. Therefore, in consideration of significant increases in scrap metal
    17       prices that have occurred in the last 5 years and the potential sale of used
    18       equipment, a zero (0) level of net salvage for production plant is recommended.
    19       On a standalone basis this recommendation results in a reduction of
    20       approximately $11. 7 million in depreciation expense based on plant as of
    21       December 31, 2008.
    22
    23   •   Mass Propertv Life Analysis. There are numerous problems with the Company's
    24       proposed life-curve combination for the various mass property accounts
    25       (transmission, distribution and general plant). First and foremost, the Company's
    26       life analysis includes the impact of hurricane activity as typical, ongoing events.
    27       This has resulted in certain accounts having life expectations shorter than
    28       basically all other utilities in the industry. In addition, the Company's consultant
    29       recognizes that there is a "significant portion" of the survivor curve to which the
    30       curve-fitting process should be geared; however he has failed to properly
    31       implement such criteria. Finally, the Company has failed to provide reasonable or
    32       adequate support for its various positions. Modifications to 16 of the Company's
    33       proposals results in a standalone impact of a $11.1 million reduction to annual
    34       depreciation expense based on plant as of December 31, 2008.
    35
I   36
    37
         •   Mass Property Net Salvage. The Company's analysis relies only on the most
             recent 5 years of data. This compares to a 16-year database employed by the same
             consultant in the current El Paso Electric Company case before this Commission.
l   38
    39
    40
             Without any indication in the testimony, depreciation study or workpapers, is the
             fact that the limited five years of data is not even maintained by account, yet it is

I   41
    42
             presented by account based on an initially unidentified data manipulation.
             Another fatal flaw in the Company's proposals is that there are the effects of
             several major hurricanes reflected in the 5-year historical database. Thus, the data
    43

!   44
    45
    46
             relied upon by the Company to propose net salvage parameters are significantly
             skewed to more negative levels than would reasonably be expected. Given the
             significant problems with the Company's presentation and database in this case,

I                                                                                               3

I
 1       retaining the existing levels of net salvage by account is recommended. On a
 2       standalone basis this recommendation results in a $10.6 million reduction in
 3       annual depreciation expense based on plant in service as of December 31, 2008.
 4
 5   •   Calculation Procedure. The Company proposes to use the Equal Life Group
 6       ("ELG") calculation procedure. The ELG procedure is not a conservative capital
 7       recovery method and in fact represents an accelerated procedure when compared
 8       to the industry standard Average Life Group ("ALO") calculation procedure. The
 9       ELG procedure is inaccurate in all instances, except in the improbable scenario
10       that future annual retirements for up to 100 years into the future can be precisely
11       estimated. In reality, ETI cannot predict future annual retirement levels with any
12       degree of accuracy, even for as little as a 5-year period. Relying on the ALO
13       procedure, a straight line, non-accelerated procedure, results in a standalone
14       reduction to annual depreciation expense of $19.3 million based on plant as of
15       December 31, 2009.
16
17   •   Combined Impact of Depreciation Adjustments. The combined impact of the
18       various depreciation adjustments is not simply the summation of the individual
19       standalone impacts. If life, net salvage, or calculation procedure proposals are
20       modified within the same account, they are interactive with each other. As set
21       forth on Schedule (JP-1 ), the combined impact of the various adjustments results
22       in a $57 million reduction in depreciation expense based on plant in service as of
23       December 31, 2008.
24
25   •   Fully Accrued Depreciation. The Company admits that it unilaterally changed
26       the Commission approved depreciation rates when it ceased booking depreciation
27       expense for three accounts. The Company does not have the authority to
28       unilaterally change a depreciation rate previously approved by the Commission.
29       Reversal of the Company's inappropriate actions results in a $6.2 million decrease
30       in rate base and a $1.5 million credit amortization expense associated with a four-
31       year amortization period.
32
33   •   Spindletop Gas Storage Facilitv l"SGSF"). Since the Company's last fully
34       litigated rate proceeding, the Company has exercised an option to purchase the
35       SGSF facilities for $1. Due to the unique situation of ownership, operation and
36       cost recovery, customers have significantly overpaid depreciation expense and are
37       now entitled to appropriate net salvage treatment and correction of the
38       intergenerational inequity that has transpired. Amortizing the excess depreciation
39       reserve over a 4-year period and recognition of Company-established net salvage
40       expectations results in a $5.5 million reduction to revenue requirements
41       associated with this unique investment. However, given Cities' witness Mr.
42       Nalepa's recommendation relating to the SGSF, only $1.2 million of my
43       recommendation associated with the recognition of net salvage is required, when
44       Mr. Nalepa's position is adopted.
45


                                                                                          4
    1    •   Storm Insurance Reserve. The Company has overstated revenue requirements in
    2        the calculation of its insurance reserve request. The Company performs a flawed
    3        Monte Carlo simulation. The Company has skewed its results to the high side
    4        based on the inclusion of inappropriate costs and charges to the insurance reserve.
    5        ETI also inappropriately attempts to segregate certain hurricane securitization cost
    6        from the reserve. Removing certain inappropriate charges to the Company's
    7        insurance reserve and performing a more realistic projection of future storm cost
    8        accruals results in a $7. 7 million reduction to the Company's storm reserve annual
     9       accrual and a $45.9 million reduction to rate base. In addition, I recommend an
    IO       increase in the current $50,000 storm insurance threshold limit to $500,000.
    11
    12   •   Cash Working Capital ("CWC"). The Company overstates and incorrectly
    13       calculates the Company's CWC requirements. In particular, the Company relies
    14       on an inconsistent implementation of service period between revenues and
    15       expenses. There are numerous other flaws associated with the Company's
    16       approach to CWC that require correction. Based on my various recommendations,
    17       the standalone impact of the corrected lead-lag analysis for the measurement of
    18       ewe requirements would result in an incremental $43.7 million reduction to rate
    19       base and an approximate corresponding $5. 7 million reduction to revenue
    20       requirements.
    21
    22   •   River Bend Decommissioning. The Company seeks approval from this
    23       Commission for its proposed level of decommissioning expense associated with
    24       the River Bend plant that is now owned by ETI's Louisiana affiliate Entergy Gulf
    25       States Louisiana ("EGSL"). Cities' witness Mr. Brazell testifies that the
    26       Commission does not have the authority to set a decommissioning revenue
    27       requirement for River Bend given EGSL' s ownership of the plant. The
    28       Company's proposal is based on a 40-year life span for River Bend, rather than
    29       the more appropriate and realistic 60-year life expectancy. Therefore, if the
    30       Commission were to determine the proper decommissioning revenue requirement
    31       for Texas retail customers, I recommend that a 60-year life span be employed. In
    32       addition, the beginning balances in the decommissioning funds are understated in
    33       the Company's presentation and would need to be corrected. The standalone
    34       impact of these adjustments eliminates the need for Texas retail customers to
    35       contribute any additional amounts to the decommissioning trust funds. Therefore,
l   36
    37
             my recommendation results in a $2.8 million reduction to proposed annual
             decommissioning revenue requirements.
    38
    39   •   River Bend Depreciation. Cities' witness Mr. Brazell presents the position that
    40       the Commission does not have the authority to set depreciation rates for River
    41       Bend. However, the Company has requested that the Commission do just that.
    42       Unfortunately, the Company's presentation reflects a 40-year service life for
    43       River Bend. It should be noted that the Company relies on a 60-year life for
    44       River Bend in the Louisiana jurisdiction and agreed to a 60-year life in Docket
    45       No. 34800, a settled proceeding. While the Company has not yet received
    46       permission from the Nuclear Regulatory Commission (''NRC") for such license

                                                                                                5
1                        extension, it must be noted that not a single license application for the 20-year life
2                        extension has been denied by the NRC. Therefore, if the Commission does elect
3                        to establish a depreciation rate for River Bend, it should do so based on the 20-
4                        year life extension and with no interim retirements reflected therein.
 5
 6   Q.         IS THERE A CONCERN THAT NEEDS TO BE ADDRESSED AT THE
 7              BEGINNING OF YOUR TESTIMONY?
 8   A.         Yes, in the area of depreciation and capital recovery a utility can present aggressive,
 9              middle of the road, or conservative parameters given the subjectivity required in
10              performing any future depreciation or capital recovery estimate. After review of the
11              Company's depreciation presentation, it is clear that the Company's position in this case
12              is one of the most aggressive presentations realistically possible. The Company's
13              approach results in an extremely excessive level of depreciation expense, rapid return of
14              capital investment to shareholders, which in my estimation, is unreasonable and an
15              unnecessary burden for current customers.
16
17   Q.         DO THE PROPOSED DEPRECIATION PARAMETERS CONTINUE THE
18              CORPORATE              PLAN       THAT        PUSHES      AGGRESSIVE      DEPRECIATION
19              PRACTICES?
20   A.         Yes. While utilities have become more sophisticated in the last several decades when it
21              comes to spelling out their corporate plans, this Company continues its predecessor's
22              Corporate Plan, which under the heading of Long-Range Corporate Objectives, stated the
23              following: "Push accounting/depreciation judgments aggressively where possible." 1
24              (Emphasis added).
25
26   Q.         CAN YOU PROVIDE SPECIFIC EXAMPLES THAT DEMONSTRATE ETl'S
27              CONTINUATION                 OF      THE        PREVIOUSLY      STATED        AGGRESSIVE
28              DEPRECIATION PRACTICES?
29   A.         Yes. First and foremost is the Company's decision to utilize the ELG calculation
30              procedure. Reliance on the ELG procedure in light of identifiable "anomalies" that result
31              from the analyses of the underlying data is flawed and can no longer be relied upon to


          1
              Gulf States Utilities Corporate Plan 1980-1984 item l(c).

                                                                                                              6
     I              predict with some degree of certainty how mortality patterns might look in the future.
     2              The anomalies in the analyses are due, at least in part, to problems with the data,
     3              including potential problems associated with the jurisdictional separation of ETI and
     4              EGSL. Indeed, the combination of the underlying data problems with the fact that the
     5              ELG procedure is the most accelerated book depreciation calculation procedure that can
     6              be proposed in a rate proceeding, can only result in a magnified distortion of the capital
     7              recovery process compared to the industry standard ALG calculation procedure.
     8
     9              Next, in the area of production plant net salvage, Mr. Spanos not only relied upon an
    I0              unsubstantiated regression analysis that produces excessively negative values, but then
    11              proposed a unique escalation calculation. The Company, through Mr. Spanos' testimony,
    12              proposes to charge current customers, who would have to pay with current dollars, for
    13              costs that have been escalated, without discounting costs back to the present, for as many
    14              as 35 years into the future. Such approach is illogical and unrealistic.
    15
    16              While there are other actions taken by Mr. Spanos that further push his and the
    17              Company's aggressive depreciation goals, the above examples more than establish the
    18              nature of the Company's presentation.



    19   SECTION II:                  DEPRECIATION

    20   1.         General
    21

I   22

    23
         Q.
         A.
                    WHAT IS DEPRECIATION?

                    There are two commonly cited definitions of depreciation. The first comes from the

I   24
    25
                    Federal Energy Regulatory Commission's ("FERC") Uniform System of Accounts
                    ("USOA"): 2

l   26                       'Depreciation', as applied to depreciable plant, means the loss in service
    27                       value not restored by current maintenance, incurred in connection with

I   28                       the consumption or prospective retirement of electric plant in the course


              2
                  Title 18 Code of Federal Regulations Part 101.

                                                                                                             7
 1                       of service from causes which are known to be in current operation and
 2                       against which the utility is not protected by insurance. Among the causes
 3                       to be given consideration are wear and tear, decay, action of the
 4                       elements, inadequacy, obsolescence, changes in the art, changes in
 5                       demand and requirements of public authorities.

 6              The second definition, from the American Institute of Certified Public Accountants
 7              ("AICPA"), is similar:

 8                      Depreciation accounting is a system of accounting which aims to
 9                      distribute the cost or other basic value of tangible capital assets, less
10                      salvage (if any) over the estimated useful life of the unit (which may be a
11                      group of assets) in a systematic and rational manner. It is a process of
12                      a/location, not of valuation. Depreciation for the year is a portion of the
13                      total charge under such a system that is allocated to the year. Although
14                      the allocation may properly take into account occurrences during the
15                      year, it is not intended to be a measurement of the effect of all such
16                      occurrences.


17   Q.         WHAT ARE THE TWO GENERAL FORMULAS USED IN DETE RMINING
18              DEPRECIATION RATES?

19   A.         The whole life and the remaining life technique are the most commonly used formulas.
20              The whole life technique is as follows: 3




                Depreciation Rate (%) =                        [         Original Cost - Net Salvage
                                                                             Average Service Life
                                                                                 Original Cost
                                                                                                              J
21              The remaining life technique for calculating depreciation rates is as follows:


22

                               ~                                                                                      J
                                                            Original Cost - Reserve - Net Salvage
      Depreoiation Rate (%)         [                                  Remaining Life
                                                                        Original Cost




          3
              A theoretical depreciation reserve calculation is developed and compared to the actual accumulated provision
                for depreciation in conjunction with the whole life technique. If the differential is significant, an
                amortization of the differential for some period of time may be recommended.

                                                                                                                        8
     1        The two formulas should equal each other when the difference between the theoretical
     2        reserve and the actual Accumulated Provision for Depreciation ("APFD" or "reserve")
     3        are recovered over the remaining life of the investment under the whole life formula.
     4
     5   Q.   ARE THERE ADDITIONAL CONSIDERATIONS IN DEPRECIATION BEYOND
     6        THE DEFINITIONS?
     7   A.   Yes. The definitions provide only a general outline of the overall utility depreciation
     8        concept. In order to arrive at a depreciation-related revenue requirement in a rate
     9        proceeding, a depreciation system must be established.
    10
    11   Q.   WHAT IS A DEPRECIATION SYSTEM?
    12   A.   A depreciation system constitutes the method, procedure, and technique employed in the
    13        development of depreciation rates.
    14
    15   Q.   BRIEFLY DESCRIBE WHAT IS MEANT BY "METHOD".
    16   A.   Method identifies whether a straight-line, liberalized, compound interest, or other type of
    17        calculation is being performed. The straight-line method is normally employed for utility
    18        depreciation proceedings.
    19
    20   Q.   BRIEFLY DESCRIBE WHAT IS MEANT BY "PROCEDURE".
    21   A.   Procedure identifies a calculation approach or grouping. For example, procedures can
    22        reflect the grouping of only a single item, items by vintage (year of addition), items by
    23        broad group or total grouping, and equal life groupings. The vast majority of utilities and

I   24
    25
              regulatory authorities use the ALG procedure.



I   26
    27
         Q.
         A.
              PLEASE BRIEFLY DESCRIBE WHAT IS MEANT BY "TECHNIQUES".
              There are two main categories of techniques with various sub-groupings: the whole life

I   28
    29
              technique and the remaining life technique. The whole life technique simply reflects
              calculation of a depreciation rate based on the whole life (e.g., a ten-year life would

I   30
    31
              imply a ten percent depreciation rate over the life of a plant). The remaining life
              technique recognizes that depreciation is a forecast or estimation process that is never

                                                                                                       9
 1        precisely accurate and requires true-ups in order to recover only 100% of what a utility is
 2        entitled to over the entire life of the investment. Therefore, as time passes, the remaining
 3        life technique attempts to recover the remaining unrecovered balance over the remaining
 4        life or other period. Most utilities rely on a remaining life technique in utility rate matters.
 5
 6   Q.   DO THE METHODS, PROCEDURES, AND TECHNIQUES INTERACT WITH
 7        ONE ANOTHER?
 8   A.   Yes. Different depreciation rates will result depending on what combination of method,
 9        procedure and technique is employed. Differences will occur even when beginning with
10        the same average service life and net salvage values.
11
12   Q.   WHAT IS NET SALVAGE?
13   A.   Net salvage is the value obtained from retired property (the gross salvage) less the cost of
14        removal. Net salvage can be either positive in cases where gross salvage exceeds cost of
15        removal, or negative in cases where cost of removal is greater than gross salvage.
16
17   Q.   HOW DOES NET SALVAGE IMPACT THE CALCULATION OF
18        DEPRECIATION?
19   A.   The intent of the depreciation process is to allow the Company to recover 100% of
20        investment less net salvage. Therefore, if net salvage is a positive 10%, then the utility
21        should only recover 90% of its investment through annual depreciation charges, under the
22        theory that it will recover the remaining 10% through net salvage at the time the asset
23        retires (e.g., 90% + 10% = 100%). Alternatively, if net salvage is a negative 10%, then
24        the utility should be allowed to recover 110% of its investment through annual
25        depreciation charges so that the negative 10% net salvage that is expected to occur at the
26        end of the property's life will still leave the utility whole (e.g., 110% - 10% = 100%).
27
28   Q.   WHAT ARE THE KEY ELEMENTS OF THE DEPRECIATION FORMULA AT
29        ISSUE IN TIDS PROCEEDING?
30   A.   All parameters in the previously noted formula are at issue. The establishment of life and
31        net salvage parameters are a function of the analyses performed, the interpretation of the


                                                                                                       10
     1        data, the judgment and experience of the       analys~   and other relevant information. In
     2        addition, the remaining life calculation is at issue given that Mr. Spanos of Gannett
     3        Fleming performs a different remaining life calculation than every other utility that does
     4        not retain Gannett Fleming that I have dealt with over the past 37 years, including this
     5        Company.     This remaining life calculation produces theoretically impossible results.
     6        Finally, the calculation procedure is a major issue in this case, as ETI does not rely on the
     7        industry standard ALG procedure.


     8        2. Production Life

     9                A. General
    10
    11   Q.   WHAT IS THE ISSUE IN TlllS PORTION OF YOUR TESTIMONY?
    12   A.   This portion of my testimony addresses the appropriate life spans for the Company's
    13        various generating units. In particular, I will address what appears to be a practice of
    14        understating the life span for generating units. I recommend longer life spans for the
    15        Company's gas-fired generating units.
    16
    17   Q.   WHAT IS A LIFE SPAN FOR A GENERATING UNIT?
    18   A.   A life span for a generating unit sets the period during which it is expected to be in
    19        service prior to being retired. For example, if a generating unit was placed into service on
    20        January 1, 1980 and had a 60-year estimated life span it would have a projected
    21        retirement date of December 31, 2040. It should be noted that a generating unit that is
    22        placed in peaking or standby service is still in service and not retired.
I   23
    24   Q.   PLEASE EXPLAIN THE SIGNIFICANCE OF SETTING AN APPROPRIATE
~   25        LIFESPAN.
    26   A.   In determining the depreciation rate, and thus depreciation expense for a generating unit,
I   27        it is necessary to establish the period over which customers are expected to receive
    28        benefits and in return pay for such benefits. This process complies with the standard
f   29        regulatory "matching principle." As previously noted, the depreciation formula includes

I                                                                                                       11

I
 1              the original cost less net salvage less the APFD, all divided by the remaining life. Thus, if
 2              the life spans, and the related remaining life, are set at too short a period, current
 3              customers overpay and vice versa. Failure to set a proper estimated retirement date for a
 4              generating unit creates intergenerational inequities and fails to comply with the
 5              "matching principle" of ratemaking.
 6
 7   Q.         ARE THE RETIREMENT DATES FOR GENERATING UNITS KNOWN WITH
 8              CERTAINTY?
 9   A.         Not for most units. Even for nuclear units that must operate within the period of a license
10              granted by the NRC, we now know that the initial estimate of a 40-year life span has been
11              or will be expanded to 60-years. Indeed, in ETI's last case, Docket No. 34800, the life
12              span for River Bend was extended for ratemaking purposes to 60 years. 4
13
14   Q.         WHEN SETTING THE LIFE SPAN FOR A GENERATING UNIT, IS IT
15              APPROPRIATE TO LIMIT THE TIME FRAME TO THE INITIAL ESTIMATED
16              PERIOD CORRESPONDING TO WHEN MAJOR CAPITAL ADDITIONS MAY
17              BE REQUIRED IN ORDER TO KEEP THE UNIT IN SERVICE?
18   A.         No, even though ETI and its depreciation consultant, Mr. Spanos, attempt to rely on such
19              a concept to artificially limit the current estimate of life span for units. Indeed, it is
20              questionable whether even the Company really believes such less than credible argument
21              given the sizeable capital additions it had to make in the early stages of service life for its
22              gas fired units. 5 In recognition of these sizeable capital additions that were necessary to
23              keep the units operating, ETI did not attempt to limit the life spans in its earlier
24              depreciation studies to the date of the expected capital additions.




          4
              PUC Docket No. 34800 Final Order FOF 34.
          s Exhibit JJS-1pages209-252.

                                                                                                            12
     1   Q.          WHY IS IT INAPPROPRIATE TO ARTIFICIALLY LIMIT THE LIFE SPAN OF
     2               A GENERATING UNIT BASED ON UNCERTAINTY AS TO WHETHER
     3               FUTURE CAPITAL ADDITIONS WILL BE MADE?
     4   A.          It is inappropriate to implement such depreciation judgment because it assumes that
     5               utilities will act differently in the future than they have acted in the past without the
     6               benefit of specific factors that would warrant such a change. Generating units are very
     7              capital-intensive items. Economic theory recognizes that it is normally expected that
     8               capital expenditures and normal maintenance expense will not only be made, but
     9               encouraged as necessary, to keep a large capital intensive facility in operation for as long
    10               as economically practical. This has been the Company's practice as it applies to actual
    11              operation of its units.
    12
    13              An analogy would be associated with the purchase of a home. A new home can easily be
    14              expected to last well over 50 years. However, a major capital expenditure for a new roof
    15              may be required after 15 to 20 years. No reasonable person would set the life expectancy
    16               of the house at 20 years because the decision has not been made regarding an expected
    17              major expenditure 20 years in the future. The same can be said about limiting the
    18              expected initial life expectancy of a house to even 30 or 40 years when the second
    19              replacement of a roof can be expected. The issue becomes at what point would one
    20              expect external forces such as a change in character of the neighborhood or other events
    21              to change, for it to warrant the abandonment of the house. As long as the best use of the
    22              house is as a dwelling and it is economically cost effective to make repairs and
    23              replacements, the initial life should not be set artificially short due to potential
    24              uncertainties surrounding future major capital additions.
I   25

I   26
    27
         Q.          DOES THE COMPANY'S PRODUCTION PLANT DEPRECIATION EXPENSE
                    REPRESENT A SIGNIFICANT REVENUE REQUIREMENT?

I   28
    29
         A.          Yes. The Company's 2008 Study identifies over $783 million of investment and proposes
                     $28.4 million in depreciation expense for annual Steam Production plant (Accounts 310-
                     316). 6 This level of depreciation expense is unnecessary and only arises as a result of the
l   30

              6
                  2008 Study at Exhibit JJS-1 page 52.
I                                                                                                              13
 I               Company's witness's aggressive "depreciation judgment" for reflecting life spans,
 2               corresponding interim retirements, and net salvage values.

 3                       B. Basis for Retirement Dates
 4
 5   Q.          WHAT TESTIMONY DID THE COMPANY SPECIFICALLY PROVIDE IN
 6              SUPPORT          OF     THE          PROPOSED   LIFE   SPANS      FOR     ITS    VARIOUS
 7               GENERATING UNITS?
 8   A.         The Company provided the testimony of Mr. Spanos. The entire basis for this significant
 9              parameter is set forth at pages 19 and 20 of Mr. Spanos' direct testimony where he states:
10
11                       The bases for the probable retirement years are life spans for each facility
12                       that are based on judgment and incorporate consideration of the age, use.
13                       size. nature of construction. management outlook, and typical life spans
14                       experienced and used by other electric utilities for similar facilities. Many
15                       of the life spans result in probable retirement years that are many years in
16                       the future, but included as part of ETI' s resource plan. As a result, the
17                       retirements of these facilities are not yet subject to specific management
18                       plans. At the appropriate time, detailed studies of the economics of
19                       rehabilitation and continued use or retirement of the facility will be
20                       performed and the results incorporated in the estimation of the facility's
21                       life span. (Emphasis added).
22
23   Q.         DID THE COMPANY ADD ANY ADDITIONAL INFORMATION REGARDING
24              THE BASIS FOR THE LIFE SPANS OF ITS UNITS IN THE 2008
25              DEPRECIATION STUDY?
26   A.         While the 2008 Study added the following statements, such verbiage fails to provide any
27               additional meaningful basis for the Company's proposed life spans:
28
29                       The life span estimates for power generating stations were the result of
30                       considering experienced life spans of similar generating units, the age of
31                       surviving units, general operating characteristics of the units, major
32                       refurbishing, and discussion with management personnel concerning the
33                       probable long-term outlook for the units. Final decisions as to date of
34                       retirement will be determined by management on a unit by unit basis. 7
35                       (Emphasis added).

          7
              2008 Study at Exhibit JJS-1 page 35.

                                                                                                         14
     1   Q.          WHAT       SPECIFIC ITEM OF INFORMATION HAS THE                             COMPANY
     2               PROVIDED IN SUPPORT OF ITS "JUDGMENT" IN ESTABLISIDNG THE
     3               LIFE       SPANS         FOR       ITS    GENERATING         UNITS        REFLECTING
     4               "CONSIDERATION OF                  THE AGE"     OR "USE, SIZE, NATURE                OF
     5               CONSTRUCTION" OF ITS UNITS?
     6   A.          The Company has provided no information that would support its proposal for a life span
     7              as short as 46 years for Sabine 5. In fact, Sabine Units 1 and 2, which are much smaller
     8              and dispatched less than Sabine 5, have already reached ages in excess of 46 years. Thus,
     9              judgment in conjunction with consideration of age or physical characteristics of the units
    10              should have caused the Company to propose longer life spans than it has.
    11
    12   Q.         WHAT        SPECIFIC ITEM               OF INFORMATION HAS THE               COMPANY
    13              PROVIDED IN SUPPORT OF ITS "JUDGMENT" IN ESTABLISIDNG THE
    14              LIFE SPANS FOR ITS GENERATING UNITS REFLECTING "MANAGEMENT
    15              OUTLOOK"?
    16   A.         The Company has provided no information that would support its proposals. In fact, the
    17              timing horizon of the Company's Strategic Resource Plan ("SRP") is through 2028. 8 The
    18              SRP planning horizon exceeds the retirement dates for all of the Company's gas-fired
    19              units, yet such plan relies on the continued operation of all such units to meet future
    20              loads. Thus, even the Company's current management "outlook" refutes the judgment
    21              employed by Mr. Spanos in the 2008 Study.
    22
    23   Q.         WHAT        SPECIFIC        ITEM OF INFORMATION HAS                  THE     COMPANY

I   24
    25
                    PROVIDED IN SUPPORT OF ITS "JUDGMENT" IN ESTABLISIDNG THE
                    LIFE SPANS FOR ITS GENERATING UNITS REFLECTING "TYPICAL LIFE

~
    26              SPANS EXPERIENCED AND USED BY OTHER UTILITIES OF SIMILAR
    27              FACILITIES"?

I   28
    29
         A.         The Company has provided no information. However, through discovery, it was
                    determined that Gannett Fleming has supported a range of life spans for gas-fired units

I   30              that is so wide that it would allow for a selection of about any value, even ones

              8
                  Response to Rose City 1-36 Attachments.

                                                                                                           15
 l              approaching 70 years. I submit that Gannett Fleming's life span range for gas-fired units
 2              is so large that it defies any credibility that might have been assigned to it in the
 3              "judgmental" process claimed by Mr. Spanos.
 4
 5   Q.         DOES MR. SPANOS' TESTIMONY PROVIDE SUFFICIENT EXPLANATION
 6              AND JUSTIFICATION TO SUPPORT THE COMPANY'S PROPOSED LIFE
 7              SPANS FOR ITS GENERATING FACILITIES?
 8   A.         No.
 9
10   Q.         DID THE COMPANY PROVIDE ANY ADDITIONAL INFORMATION JN
11              RESPONSE TO DISCOVERY?
12   A.         Yes. Mr. Spanos provided his site visit notes that reference limited additional information
13              such as:
14
15                       •       System maintenance good;
16                       •       Control upgrades;
17                       •       Monthly vibration program, performance tests; and
18                       •       Boiler exam and maintenance every year. 9
19
20   Q.         DO THESE ADDITIONAL STATEMENTS CONTAINED IN MR. SPANOS' SITE
21              VISIT NOTES PROVIDE SUFFICIENT SUPPORT FOR THE COMPANY'S
22              LIFE SPAN PROPOSALS?
23   A.         No. These statements represent the type of statements one would expect relating to a
24              dynamic situation requiring decisions whether to retire units or continue to expend funds
25              to permit continued operation. In fact, it is quite clear from these comments and other
26              information in the 2008 Study that the Company has historically decided, and currently is
27              deciding, to make necessary capital expenditures to keep its units in operation long after
28              the claimed initial design life. The Company has faced the decision whether to retire
29              these units or spend funds to keep them in operating condition beyond initial expectations
30              and in each instance has decided that it is economically appropriate and efficient to do
31              what all other utilities have been doing: maximize the life of a capital-intensive asset.

          9
              Response to Rose City 1-15 Attachment.

                                                                                                        16
     1               There is more support for longer life spans in Mr. Spanos' notes than there is for the
     2               artificially short life spans being proposed.
     3
     4   Q.          DID      MR.      SPANOS         PROVIDE         ANY   ADDITIONAL         INFORMATION
     5               REGARDING ms PROPOSED LIFE SPANS DURING ms DEPOSITION?
     6   A.          Yes. Mr. Spanos stated that the life spans corresponded with the best estimate of the
     7               likelihood of assets being either taken out of service (i.e. retired), or the date of expected
     8               major capital additions in the future made to change the functionality of the asset. 10 He
     9               also admits that the proposed retirement in his study does not necessarily relate to when
    10               the units would be shut down. 11 These two statements taken together default to a position
    11              that the probable retirement dates in Mr. Spanos' study are the unsubstantiated date Mr.
    12               Spanos assumes the Company may make major capital additions to change the
    13               functionality of the units.
    14
    15   Q.         IS THERE ANYTHING IN THE USOA THAT DEFINES OR TIES THE
    16               SERVICE PERIOD FOR A GENERATING UNIT TO AN ASSUMED DATE
    17               WHEN A UTILITY MIGHT MAKE A MAJOR CAPITAL ADDITION THAT
    18               CHANGES THE FUNCTIONALITY OF AN ASSET?
    19   A.          Absolutely not.
    20
    21   Q.          DID MR. SPANOS OR THE COMPANY PROVIDE A SINGLE DOCUMENT
    22               THAT DEMONSTRATES THE PROPOSED RETIREMENT DATES ARE THE
    23               COMPANY'S BEST ESTIMATE OF WHEN A UNIT WILL RETIRE?

I   24
    25
         A.          No. In fact, as previously discussed, the documents presented by the Company now
                     demonstrate that assumed retirements prior to 2029 are not the current best estimate of

~   26               the Company.



~
I             10
                   Deposition of Mr. Spanos on April 20, 2010 at TR 39.
                   Id.
I
              II


                                                                                                                17

!
 1   Q.   DID MR. SPANOS PROVIDE A SINGLE DOCUMENT OR ITEM OF
 2        EVIDENCE THAT IT IS APPROPRIATE TO TIE                                THE PROPOSED
 3        RETIREMENT DATE TO A CONCEPT OF WHEN MAJOR CAPITAL
4         EXPENDITURES MIGHT OCCUR?
 5   A.   No, Mr. Spanos' concept is a backdoor approach to recognizing interim additions,
 6        something the PUC and other regulators do not permit.
 7
 8   Q.   WHAT ARE INTERIM ADDITIONS?
 9   A.   Interim additions are theoretical future dollars of investment or capital additions in plant
10        to be added to existing facility of the Company. Such additions are not the dollars of
11        investment currently in service. Rather, they are .estimated dollars for replacement of
12        certain existing facilities or for additions of new facilities to an existing generating
13        facility in the future.
14
15   Q.   ARE      INTERIM          ADDITIONS      APPROPRIATE           FOR      DEPRECIATION
16        PURPOSES?
17   A.   No. Interim additions are inappropriate since they reflect the estimation of potential
18        additions to plant-in-service that currently do not exist and are not used and useful in
19        providing service. Interim additions may never actually occur or may occur at a much
20        different date or amount than initially assumed.
21
22   Q.   IN THE RATEMAKING PROCESS, ARE INTERIM ADDITIONS EVER
23        APPROPRIATE FOR DEPRECIATION PURPOSES?
24   A.   No. Interim additions are appropriate only after they occur. Once such expenditures
25        occur, and the plant becomes used and useful in providing service, it is appropriate to
26        incorporate the plant investment into a depreciation study. Under this approach, the
27        Company is not deprived of a return of its investments associated with interim additions.
28        Moreover, customers are not inappropriately charged for unknown plant that is not used
29        and useful in providing service to them at the time the depreciation rates are developed.




                                                                                                      18
     1   Q.          WHAT SOURCE SUPPORTS YOUR POSITION THAT ESTIMATED INTERIM
     2               ADDITIONS SHOULD NOT BE REFLECTED IN THE DEPRECIATION
     3               CALCULATION?
     4   A.          The National Association of Regulatory Utility Commissioners (''NARUC") 1968
     5               publication entitled Public Utility Depreciation Practices describes, on pages 133 and
     6               134, how interim additions are treated. It states the following:

     7                        Appropriate computations must be made for such interim retirements, but
     8                        interim additions are not considered in the depreciation computation until
     9                        they are actually made.
    10                        It is possible to estimate the probable future retirements and additions to a
    11                        particular piece ofproperty and thus arrive at a single depreciation rate
    12                        applicable over the entire life of the property. This is an unsatisfactory
    13                        practice inasmuch as considerable speculations would be required to
    14                        make such an estimate on future additions. In any event. this is not
    15                        necessary inasmuch as the depreciation accrual can be adjusted in future
    16                        years as additions are made. (Emphasis added).
    17
    18   The 1996 NARUC depreciation publication reaffirms this concept. 12
    19

    20   Q.          HAS THE FERC RENDERED A DECISION ON THE CONCEPT OF
    21               INTERIM ADDITIONS?

    22   A.          Yes.      The FERC reviewed and ruled on this issue in its Opinion No. 165, a
    23               Commonwealth Edison Company case. 13                     In that case, Commonwealth Edison had
    24               proposed taking into account budgeted future interim additions and stated that without the
    25               inclusion of the budgeted interim additions, there would be a violation of the matching

I   26
    27
                     principle (i.e. revenues collected corresponding to the expenses incurred). In Opinion
                     No. 165, the FERC clearly rejected recognition of interim additions:

I   28
    29
                              ... we reject its [Edison 'sj claim that this will leave some costs
                              unrecovered after the plant is retired. Such a result might occur if
    30                        Commonwealth would fail to adjust its depreciation rates from time to
I   31
    32
                              time, taking into account up-to-date information on changes in plant
                              balances, estimated remaining life, salvage and removal cost experience,
    33                        and accumulated provision for depreciation to date.            However,
I             12
                   Page 142 states" ... interim additions are not considered in the depreciation base or rate until they occur."
              13
                   23 FERC paragraph 61,219 (1983)

                                                                                                                                   19
 1                      Commonwealth not only is free to make such adjustments to its
 2                      depreciation rates, but is obligated to do so to assure that as near as
 3                      possible the service value of electric plant is fully recovered during its
 4                      useful life. For all these reasons, we find no basis to approve
 5                      Commonwealth's depreciation methodology. 14
 6
 7   Q.          IS THERE A NEED TO SPECULATE ON THE COMPANY'S FUTURE
 8               INTERIM ADDITIONS?

 9   A.         No. The Company will have the opportunity to recover actual additions to plant from
10               customers once they occur.
11
12   Q.         ARE OTHER UTILITIES FACED WITH THE SAME CONCERNS RELATING
13              TO THE DECISION TO REPAIR OR REPLACE WORN OR BROKEN
14               COMPONENTS VERSUS RETIRE A UNIT?
15   A.          Yes, and the trend in the industry has been to project even longer life spans. In fact, in a
16              recent case here in Texas, Southwest Electric Power Company ("SWEPCO") filed for life
17              spans longer than ETI has for comparable units. 15 A listing of comparable size and age of
18               generating units between SWEPCO and ETI, along with the life spans filed by both
19              utilities is set forth in the table below:
20
21                                              COMPARABLE UNITS


                              Size      Year        Life                        Size      Year        Life
          ETIUnit            (MW)     Installed     Span      SWEPCOUnit      <MW)      Installed     Span
     Lewis Creek # 1          271        1970        55        Wilks #2         357        1970        65
     Lewis Creek #2           271        1971        54        Wilks #3         358        1971        65
       Sabine #1              240        1962        63        Wilks #1         175        1964        65
       Sabine #2              240        1963        62        Willes #1        175        1964        65
       Sabine #3              473        1967        58        Willes #2        357        1970        65
       Sabine #4              592        1974        51       KnoxLee#5         344        1974        65
       Sabine #5              507        1977        46       KnoxLee#5         344        1974        65




          14
               23 FERC at page 61,469.
          15
               PUC Docket No. 37364, Exhibit DAD-I page 25.

                                                                                                            20
     1                     C. Recommendation
     2
     3   Q.        DO YOU BELIEVE THE COMPANY'S PROPOSED RETIREMENT DATES
     4             FOR GENERATING UNITS ARE APPROPRIATE FOR DEPRECIATION
     5             PURPOSES?
     6   A.        No. The Company's proposed life span for its gas-fired generating units assumes a 2025
     7             retirement date. The Company's most recent SRP clearly dispels the credibility of that
     8             date. Moreover, the Company has not shown why it cannot obtain life spans for its units
     9             comparable to what other utilities have already achieved or are now projecting.
    10
    11             Finally, there is no credible basis for the Company to propose that the largest two gas-
    12             fired units, Sabine Units 4 and 5, will only be able to achieve life spans of 51 and 46
    13             years, respectively, while its two smallest and oldest units, Sabine Units 1 and 2, are
    14             projected in the 2008 Study to achieve life spans of 63 and 62 years, respective. 16 These
    15             life span estimates are extended at least to 67 and 68 years, respectively in the most
    16             current SRP. The Company's production life span proposals are neither logical nor
    17             credible.
    18
    19   Q.        IS THERE ANY DOUBT THAT GAS-FIRED STEAM GENERATING UNITS
    20             CAN LAST AS LONG AS 65 YEARS OR LONGER?
    21   A.        No. First, ETI now recognizes that Sabine Unit 1 will operate for at least that length of
    22             time. 17 In addition, Mr. Spanos supports life spans for gas-fired units of up to 67 years for
    23             Entergy Arkansas, Inc. ("EAi"), ETl's sister utility in Arkansas. 18 Moreover, the U.S.
    24             Energy Information Administration ("EIA") maintains a database of operating generating
    25             units in service through 2008. That database identifies over 500 natural gas-fired units

~   26             that had already reached 46 years of age (the short life span proposed for Sabine 5) by the
    27             end of2008, with almost 30 of those units exceeding 200 MW in size. 19

I
I             16
              17
              18
                 Exhibit JJS-1page36.
                 Response to Rose City 1-36.
                 Response to Rose City 1-3, 2008 Study for EAi at page 11-27.
              19
                 EIA FORM 860, file Gen YOS.
I                                                                                                             21

I
 1   Q.   WHAT DO YOU RECOMMEND?
 2   A.   Given the industry, even here in Texas, is moving to a minimum of 60 years for coal-
 3        fired generation and 60 plus years for gas-fired generation, I recommend a life span for
 4        all gas-fired units corresponding to the year 2029 for those units that will exceed 65 year
 5        life spans by that time, and a life span of 65 years for the remaining units. The year 2029
 6        corresponds to the earliest year subsequent to the Company's current planning horizon in
 7        its SRP.

 8        3. Production Interim Retirements
 9
10   Q.   WHAT IS THE ISSUE IN TIDS PORTION OF YOUR TESTIMONY?
11   A.   This portion of my testimony addresses the Company's request for interim retirements
12        and the corresponding impact on the life span for production plant.
13
14   Q.   WHAT ARE INTERIM RETIREMENTS?
15   A.   Interim retirements have been characterized as a fine-tuning adjustment to the life-span
16        analysis. The life-span method is used in estimating the retirement date for any large unit
17        of property such as an entire generating facility to recognize that through the course of its
18        60-year life span, several components of that generating facility will be changed. The
19        theory behind interim retirement rates is that even though a large unit of property, such as
20        a generating facility might retire in 60 years, in the interim period many components have
21        to be replaced in order to maintain the overall generating facility in operating condition.
22        An analogy to this would be a car, which might be anticipated to have a service life of 10
23        years. During the 10-year life of the car, the owner might have to replace the battery,
24        tires, alternator and other components in order to maintain the automobile in a safe and
25        operable condition. Therefore, even though the automobile may have a 10-year life span,
26        a 9.8-year average service life ("ASL") for the automobile and its components would
27        result due to the averaging of the automobile's life span with the average of the
28        individual components. In other words, the interim retirement rate would be a fine-
29        tuning factor used to reduce the service life from 10 years to a 9.8 year ASL.




                                                                                                    22
     1   Q.        HAS THE COMPANY INCORPORATED THE IMPACT OF INTERIM
     2             RETIREMENTS IN ITS DEPRECIATION ANALYSIS?
     3   A.        Yes. 20
     4
     5   Q.        HAS THE COMMISSION PREVIOUSLY REJECTED THE INCLUSION OF
     6             INTERIM RETIREMENTS IN THE CALCULATION OF PRODUCTION PLANT
     7             DEPRECIATION RATES?
     8   A.        Yes. The Commission has specifically and consistently excluded interim retirements
     9             from prior production-plant depreciation-rate calculations in fully litigated rate cases. In
    10             Docket Nos. 14965 and 16705, the most recent fully litigated major electric base rate
    11             cases where interim retirements were an issue, the Commission once again reaffirmed its
    12             position and rejected the inclusion of interim retirements from the depreciation rate
    13             calculation for production plant.        In Docket No. 14965 the Commission stated " ...
    14             forecasted interim additions and retirements and net salvage increases to plant in service
    15             are not known and measurable changes to test-year invested capital."21           (Emphasis
    16             added). In Docket No. 16705 the Commission denied the impact or recognition of all
    17             interim retirements and additions beyond the end of the test year. 22 The Commission has
    18             also denied the inclusion of interim retirements in cases where I also recommended their
    19             inclusion.
    20
    21   Q.        WAS MR. SPANOS AWARE OF COMMISSION PRECEDENT WHEN HE
    22             PROPOSED THE INCLUSION OF INTERIM RETIREMENTS?
    23   A.        Yes. However, he believed that the precedent dealt with future interim retirements, not
    24             historical interim retirements. 23 While his analysis of interim retirements was based on
I   25             historical data, the results were applied to future remaining lives because Mr. Spanos
    26             thinks "that is a good indicator of what is going to happen into the future for interim
~   27             retirement purposes."24 Mr. Spanos' approach is no different than the practices of other
    28             utilities where the Commission rejected the use of interim retirements. In fact, Mr.
~
              20
                 Direct Testimony of Mr. Spanos at page 18.

I             21
              22
              23
                 Docket No. 14965 FOF 94.
                 Final Order Docket No. 16705 at FOF 186.
                 Deposition of Mr. Spanos on March 25, 2010 at TR 93-94.
              24


I                Deposition of Mr. Spanos on April 20, 2010 at TR 95-96.

                                                                                                            23

I
 l             Spanos could not identify any docket where this Commission had allowed interim
 2             retirements as he would characterize them. 25
 3
 4   Q.        IF THE COMl\flSSION WERE INCLINED TO REVERSE ITS PRECEDENT ON
 5             TIDS ISSUE IN Tms CASE, DO YOU BELIEVE THE ANALYSIS PRESENTED
 6             BY THE COMPANY IS APPROPRIATE?
 7   A.        No.
 8
 9   Q.        WHAT DOES THE COMPANY PROPOSE FOR INTERIM RETIREMENTS?
10   A.        The Company proposes to implement a calculation procedure for interim retirements
11             based on a truncated interim retirement survivor curve. 26
12
13   Q.        PLEASE EXPLAIN THE PROBLEMS WITH THE COMPANY'S PROPOSED
14             METHOD.
15   A.        The Company's approach relies on an actuarial analysis of the historical data for the
16             investment in Accounts 311 through 316.27 Actuarial analyses are normally performed on
17             more homogenous-type investments. The types of investments booked in the major steam
18             production plant accounts are non-homogeneous and do not reasonably lend themselves
19             to actuarial analyses. In other words, the retirement forces experienced by boiler tubes
20             booked in Account 312 may be noticeably different than those affecting the lighting
21             system, also booked in Account 312. Moreover, the retirement of individual units of
22             property in Account 312 can vary significantly. Therefore, Mr. Spanos' reliance on an
23             inappropriate method, which in turn relies on non-homogenous data to "guess" at a 55-R2
24             life-curve combination for the largest production plant account, is inappropriate. I use the
25             term "guess" given the fact that Mr. Spanos analysis yielded a survivor curve that only
26             declined by 12 percentage points out of 100 percentage points for a full curve. He simply
27             "guesses" or forces a result for the remaining 88%. Moreover, his "guess" at the 12%
28             decline in the observed life table ("OLT") was not good or reasonable. 28 If the


          25
             Id., at TR 96.
          26
             Exhibit JJS-1, pages 209-254.
          27
             Id., at pages 56-80.
          28
             OLT reflects the actual retirement pattern exhibited over a given period.

                                                                                                        24
     1               Commission were inclined to change its precedent on this matter, "guessed" at or forced
     2              results cannot be accepted as a valid basis for the inclusion of the impact of interim
     3              retirements.
     4
     5              Another consideration relating to Mr. Spanos' proposal in this case is his constant
     6              practice of relying on industry data. With this in mind, it is worth noting that Mr. Spanos
     7              proposed much longer ASLs for the same accounts in his current El Paso Electric
     8              testimony before the Commission, as shown in the table below.
     9
    10                          COMPARISON OF INTERIM RETIREMENT CURVES
                                                                               Increase to EPE
                     Account               ETI                 EPE          Years             %
                       311                65-R2              100-Sl.5          35                54%
                       312                55-R2              80-82.5           25                45%
                       314               50-82.5              75-R4            25                50%
                       315               50-S0.5             65-Sl.5           15                30%
                       316               50-Rl.5              60-R3            10                20%


    11              Moreover, it must be noted that Mr. Spanos had basically the same level of utility
    12              specific OLT data with which to work with in both cases. Therefore, it appears that the
    13              difference between the two contemporaneous studies both filed at the same time before
    14              this Commission is the depreciation policy in place for ETI. Finally, it is worth noting
    15              that the Florida Public Service Commission ("FPSC") this year denied the method of
    16               calculating interim retirement employed by Gannett Fleming recognizing many of the
    17              problems noted above. 29

I   18
    19   Q.          WHAT DO YOU RECOMMEND?

I   20
    21
         A.          Given that this Commission has consistently denied the recognition and inclusion of
                     interim retirements for production-plant deprecation rates in prior proceedings, I

I   22
    23
                     recommend that the Commission precedent on this matter be recognized for ratemaking
                     purposes in this proceeding and the impact of interim retirements be eliminated from the

I   24               Company's proposed depreciation calculation.

              29

I                  FPSC Docket No. 080677-EI Order at pages 30-32.

                                                                                                            25

I
 1   Q.        WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
 2   A.        The total standalone impact of the elimination of the proposed interim retirements from
 3             production plant depreciation rates results in a reduction to the Company's requested
 4             depreciation expense by $4,608,437 based on plant as of December 31, 2008.

 5             4. Production Net Salvage
 6
 7   Q.        WHAT ISSUE DO YOU ADDRESS IN TIDS PORTION OF YOUR
 8             TEST™ONY?
 9   A.        I address the Company's request for production net salvage. Specifically, the Company
10             requests net salvage for its various generating facilities ranging from a negative 15% to a
11             negative 32% for its various generating facilities. 30 In response to the Company's
12             proposal, I recommend a zero (0) level of net salvage, even though a more appropriate,
13             yet still conservative, level would be a positive 5% to 10%.
14
15   Q.        WHAT DOLLAR IMPACT DOES THE COMPANY'S PROPOSAL HAVE ON
16             DEPRECIATION EXPENSE?
17   A.        Based on plant in service as of December 31, 2008, the Company's net salvage request of
18             $190.7 million over the life of the investment produces approximately $11.6 million of
19             annual depreciation revenue requirements. 31
20
21   Q.        WHAT IS THE COMPANY'S BASIS FOR ITS REQUEST OF NEGATIVE NET
22             SALVAGE?
23   A.        Mr. Spanos states the following:
24
25                     final net salvage of dismantling costs of steam production units was based
26                     on common industry practices of linear regression analysis by Megawatts
27                     (capacity). These analyses were performed as of 2008 and the overall
28                     dismantling costs were projected to the date of removal. 32




          30
             Exhibit JJS-1, pages 51 and 52.
          31
             Exhibit JJS-1, pages 51 and 52, setting the net salvage percentage to zero {O).
          32
             Direct Testimony of Mr. Spanos at page 22.

                                                                                                       26
     1              In other words, the Company performed what it claims is a common industry practice of
     2              performing linear regression analysis on some unidentified data set to arrive at an
     3              unidentified regression equation, which can then be applied to the individual megawatt
     4              size of the Company's generating units. Once a current cost value has been established
     5              under this method, Mr. Spanos then escalated the costs into the future until the proposed
     6              retirement date for the Company's various generating units.
     7
     8   Q.         CAN YOU PROVIDE A SPECIFIC EXAMPLE OF WHAT THE COMPANY
     9              PROPOSES?
    10   A.          Yes. Mr. Spanos claims his regression analysis yields a $40.61 per kW dismantlement
    11              cost for the Big Cajun coal-fired generating unit. 33       He then applies that value to the 588
    12              Mw size of the Big Cajun coal unit, which yields an estimated cost of $23,878,680 in
    13              2008 dollars. Mr. Spanos then applied ETI's 42.5% ownership share of what he believed
    14              was the Entergy ownership share of the Big Cajun unit, in an attempt to establish a
    15               $10,148,439 cost applicable to ETI. Mr. Spanos inflated that 2008 cost figure at an
    16              annual compounded rate of 3% for 3 5 years into the future, the assumed future retirement
    17              date for the Big Cajun unit. The result is an estimated future dismantlement cost of
    18               $28,536,311. 34 The future escalation of cost raised the requested cost level by multiplying
i   19              the current cost level by a factor of 2.814 (l.03<35   ».
    20
    21   Q.          SETTING ASIDE FOR THE MOMENT THE REGRESSION AND ESCALATION
    22               CONCEPTS           EMPLOYED          BY   MR.   SPANOS,          IS   ms     CALCULATION
    23               CORRECT?
                     No. For Big Cajun and Nelson 6, Mr. Spanos failed to reduce the stated MW size of the
I   24
    25
         A.
                     units for Entergy's ownership share. While Mr. Spanos did apply a 42.5% ownership

I   26
    27
                     share allocation between ETI and Entergy Gulf States Louisiana ("EGSL"), he failed to
                     recognize that these are jointly owned units with other utilities. In particular, Cajun

l   28
    29
                     Electric Power Company, Inc. owns 58% of the Big Cajun unit, while other utilities own
                     30% of Nelson 6. Therefore, Mr. Spanos' calculation overstates the dismantlement cost

I             33
                   Exhibit JJS-1page189, column (a).
              34
                   $10,148,439 X l.03 3S = $28,536,31).

                                                                                                                  27
 1             for these units even if one were to accept his linear regression and future cost escalation
 2             approach.
 3
 4   Q.        IS THE LINEAR REGRESSION ANALYSIS AS PROPOSED BY MR. SPANOS A
 5             COMMON INDUSTRY PRACTICE AS CLAIMED?
 6   A.        No. In fact, when requested to provide support for such claim, all Mr. Spanos could state
 7             was that it "is utilized by many utilities."35 Clearly, the claim is incorrect. Indeed, no
 8             other use of the "common" industry approach was found in review of the recent
 9             testimonies of Mr. Spanos.36
10
11   Q.        WAS MR. SPANOS REQUESTED TO IDENTIFY OTHER UTILITIES WHERE
12             GANNETT FLEMING HAD EMPLOYED A METHOD OTHER THAN LINEAR
13             REGRESSION ANALYSIS FOR PRODUCTION PLANT NET SALVAGE
14             DURING THE PAST 3 YEARS?
15   A.        Yes. Surprisingly, Mr. Spanos only identified two examples in response to this request
16             for information. 37 What is surprising about Mr. Spanos' response is that he currently has
17             a Gannett Fleming depreciation study on behalf of El Paso Electric before the
18             Commission in Docket No. 37690. In that depreciation study, Mr. Spanos did not employ
19             a linear regression analysis for production plant net salvage. In other words, two
20             contemporaneous depreciation studies performed on two different utilities both providing
21             service in Texas, both of which have been filed before this Commission, reflect
22             inconsistent application of what Mr. Spanos claims is a "common'' industry practice.
23
24   Q.        DID MR. SPANOS IDENTIFY             ms    STANDARD FOR PRODUCTION PLANT
25             DISMANTLEMENT COSTS DURING A RECENT DEPOSITION?
26   A.        Yes. In the El Paso Electric case noted above, Mr. Spanos stated during his deposition the
27             following regarding his standards for production plant terminal net salvage:




          35
             Response to Rose City 12-S(a).
          36
             Response to Rose City 1-3.
          37
             Response to Rose City 12-5(b).

                                                                                                       28
     1                       I feel as though you need to incorporate a terminal net salvage component
     2                       or a -- what's called a decommissioning study to be incorporated into the
     3                       development.
     4                       However, if the company has not gone through the practice of getting the
     5                       estimate on that or does not have any determination of what their plans are
     6                       at final dismantlement, it's, in my opinion, not proper to build in a
     7                       terminal net salvage component without some sort of support.
     8                       The company [El Paso Electric] at this time hadn't had any plans, so
     9                       we've not included that. But there is going to be a major cost to dismantle
    10                       these facilities, and that needs to be built into rates for production facilities
    11                       as a full-service value of that facility.
    12                       But unless you have a specific plan or at least an idea of what's going to
    13                       happen, I don't think it is wise to build that into rates. But I think that's
    14                       something that's going to be a consideration here. 38 (Emphasis added.)
    15
    16              In other words, Mr. Spanos has established his standard for production plant terminal net
    17              salvage in the El Paso Electric case, which is inconsistent within his proposal in this
    18              proceeding. He admits that it is not proper to build in a terminal net salvage component
    19              without some sort of support. Neither ETI nor El Paso Electric produced a
    20               decommissioning cost estimate and neither have specific plans as to what would transpire

I   21               at the time of retirement.
    22
    23   Q.          CAN MR. SPANOS CLAIM THAT HE DID NOT HAVE THE DATA
    24              NECESSARY TO PERFORM THE "COMMON INDUSTRY PRACTICE OF
    25               LINEAR REGRESSION ANALYSIS" IN THE EL PASO ELECTRIC CASE
    26               THAT HE HAS PROPOSED IN TIDS CASE?
    27   A.         No. Mr. Spanos claims that his firm obtained this data in the early 1990s. Thus, Mr.
    28               Spanos had the information available for his El Paso Electric study and testimony, yet

I   29               found it not wise to rely on it there, unlike his decision in this proceeding.



1

I
              38
                   Deposition of Mr. Spanos on March 25, 2010 in Docket No. 37690 at page 86.

                                                                                                                 29
 1   Q.   SETTING ASIDE MR. SPANOS' FAILURE TO COMPLY WITH                              ms   OWN
 2        STANDARD AND         ms    INCONSISTENT TREATMENT BETWEEN EL PASO
 3        ELECTRIC AND ETI, ARE THERE MAJOR PROBLEMS WITH THE
 4        COMPANY'S PROPOSED REGRESSION ANALYSIS?
 5   A.   Yes. The Company's basis for its production net salvage has almost too many problems
 6        to enumerate. However, the following are some of the major problems:
 7
 8               •   No underlying data exists to support the claimed regression data points;
 9               •   No first-hand knowledge exists of where the data came from;
10               •   Assumed future inflation rates are inconsistent with what the Company's rate
11                   of return witness is proposing in this case;
12               •   Proposing that current customers pay with current dollars for future inflated
13                   costs while failing to discount such costs back to a present value level is
14                   rmproper;
15               •   Reliance on a false premise that the data points in the regression analysis
16                   represent actual dismantlement costs of generating units over many years,
17                   rather than being associated with dismantlement cost estimates for plants that
18                   have not been dismantled is improper;
19               •   Mathematical errors exist in the net salvage process; and
20               •   Failure to recognize or understand the dramatic underlying differences
21                   between assumed values or values within the regression database associated
22                   with comparable sized units leads to flawed results in addition to the flawed
23                   results generated by the flawed analysis.
24
25   Q.   PLEASE DESCRIBE THE DATABASE RELIED UPON BY MR. SPANOS TO
26        DEVELOP ms REGRESSION ANALYSIS.
27   A.   As set forth in the Company's response to Rose City 12-5, Mr. Spanos claims
28        approximately 60 data points associated with demolition costs for coal-fired generating
29        facilities. However, he does not have a single item of information associated with the
30        underlying data points. In other words, he cannot identify the units, stations, year in
31        which the dismantlement supposedly occurred, the process employed, the utility at issue
32        or anything else about the underlying data. Review of the data points indicates a mixture
33        of individual units with stations that are comprised of multiple units. The smallest data
34        point reflects 21 megawatts, while the largest data point reflects 3,145 megawatts. I am
35        unaware of any single generating unit that begins to reflect a size even approaching 3,000
36        MW.


                                                                                                 30
     1
     2   Q.   DO VALUES IN MR. SPANOS' REGRESSION DATA SET REPRESENT
     3        UNREALISTIC RANGES?
     4   A.   Yes. For example, at the low end of the MW size range, Mr. Spanos identifies a 21 MW
     5        and a 23 MW unit. The observed values for these two similarly sized coal units are a
     6        $38.14 per kW dismantlement cost and a $119.22 per kW dismantlement cost,
     7        respectively. This cost range represents in excess of a 3 to I variance from the low value
     8        to the high value. Ranges of this magnitude for the same type and size units call into
I    9        question the validity of the data. However, Mr. Spanos does not have the underlying data
    IO        and cannot explain such variances.
    11
    12   Q.   IS THE UNREALISTIC LEVEL OF VARIANCE LIMITED TO ONLY THE
    13        SMALLEST SIZE UNITS?
    14   A.   No. For example, Mr. Spanos' database includes a 610 MW and a 630 MW unit with
    15        corresponding estimated decommissioned costs of $8.96 per kW and $84.33 per kW,
    16        respectively. Again, this range represents a differential in excess of 9 times from the low
    17        value to the high value. Ranges of this magnitude for similar size and type units
    18        demonstrate that Mr. Spanos' unsubstantiated database does not produce credible values.
    19
    20   Q.   DOES THE FACT THAT MANY OF THE VALUES FALL WITHIN MORE
    21        REALISTIC RANGES HELP JUSTIFY RELIANCE ON THE REGRESSION
    22        ANALYSIS?
    23   A.   No. Without access to the underlying data, we do not know whether the majority of the
    24        values in the more plentiful middle range are not a function of cost estimates from the
    25        same cost estimator firm, thus further diminishing the credibility of the database.

~   26
    27   Q.   YOU STATE THAT THESE VALUES ARE ESTIMATED VALUES, DOES MR.

!   28
    29   A.
              SPANOS AGREE WITH YOU?
              No. During Mr. Spanos' deposition, he stated that he believed that the values reflected in

I   30        his database were for actual demolition activity, rather than estimated demolition cost



I                                                                                                     31


I
 1             studies. 39 Mr. Spanos' understanding of the data is based on his undocumented
 2             discussions with his predecessors at Gannett Fleming. 40
 3
 4   Q.        IS MR. SPANOS CORRECT?
 5   A.        No. This is the first time I have heard Mr. Spanos claim that these were actual demolition
 6             cost studies. For example, when Mr. Spanos relied on a regression analysis for his
 7             proposed production plant net salvage proposal in a Nevada Power Company (''NPC")
 8             case before the Nevada Public Service Commission (''NPSC"), he believed the values
 9             were from estimated cost studies.41 In that case, Mr. Spanos also stated that the "data
10             [demolition cost information] were obtained from a survey conducted by the Property
11             Accounting and Valuation Committee of the Edison Electric Institute.''42 However, Mr.
12             Spanos' statements regarding these studies included discussion of different contingency
13             factors between studies. If the data represented actual completed demolition of power
14             plants, there would be no need for references to contingency factors. Contingency factors
15             are only applicable to future occurrences. The most troubling aspect of this situation is
16             that Mr. Spanos now claims he has even less of the limited data he had in the NPC case
17             associated with the old demolition cost estimates in this case.
18
19   Q.        IS THERE YET ANOTHER PROBLEM WITH THE RELIANCE ON A 20-YEAR
20             OLD UNIDENTIFIED DATABASE?
21   A.        Yes. Productivity rates and types of potential demolition activities have changed over
22             time. For example, there now exists a mechanical boom that can reach 300 ft high with
23             sheers on the end that can sever large beams of steel. This type of equipment has changed
24             the productivity levels reflected in whatever studies Mr. Spanos relied upon in
25             comparison to today's activity. In addition, Mr. Spanos' reliance on demolition cost
26             studies fails to recognize that many portions of units may be sold, which diminishes the
27             level of negative net salvage or, in fact, results in positive levels of.net salvage. Another
28             consideration that Mr. Spanos fails to take into account is the possibility of reuse of the


          39
             Deposition of Mr. Spanos on April 20, 2010 at TR 117.
          40
             Id.
          41
             NPSC Docket Nos. 03/1001-03/1002.
          42
             Rebuttal Testimony Mr. Spanos, page 16 in NPC Docket Nos. 03-1001/03-1002.

                                                                                                         32
     1               facilities by ETI. Most of the decommissioning studies in the late 80s and early 90s
     2               reflect a substantial amount of dollars for site restoration. Such costs would be
     3               inappropriate if a utility were to reuse the facility, as those costs would be associated with
     4               the new installation. Simply put, multiple problems with the Company's production net
     5               salvage analysis render it unreliable for any purpose in this proceeding.
     6
     7   Q.          DOES MR. SPANOS FURTHER EMPLOY AN EXCESSIVE DEPRECIATION
     8               CONCEPT IN ms PRODUCTION PLANT NET SALVAGE PROPOSAL?
     9   A.          Yes. After inconsistently relying on a linear regression analysis for his proposal in this
    10               case and obtaining results that lack credibility, Mr. Spanos takes another major
    11               inappropriate step. That step is to escalate the results of his regression analysis for net
    12               salvage costs into the future until the projected date of retirement. Mr. Spanos relies on a
    13               3% inflation factor, which he claims is representative of the Consumer Price Index
    14               ("CPI") over the last 40-50 years. 43
    15
    16   Q.          DID MR. SPANOS DISCOUNT THE FUTURE ESCALATED COST BACK TO
    17               THE PRESENT PERIOD?
    18   A.         No. Mr. Spanos believes that the negative net salvage to be reflected in current rates must
    19               include the cost to demolish a unit at the time of retirement. 44 In other words, Mr. Spanos
    20               proposes to have current customers pay in current dollars for future costs that may have
    21               been escalated as many as 3 5 years into the future.
    22
    23   Q.          IS TIDS APPROPRIATE?
    24   A.          No.
I
~
I
l             43
                   Deposition of Mr. Spanos on April 20, 2010 at TR 125.
              44
                   Id., at TR 124.

                                                                                                                 33
 l   Q.         HAVE OTHER COMMISSIONS DENIED REQUESTS FOR INCLUSION OF
 2              FUTURE INFLATION IN THE CALCULATION OF PRODUCTION-PLANT
 3              NET SALVAGE?
 4   A.         Yes. Recently, the Oklahoma Corporation Commission ("OCC") denied the identical
 5              request in a Public Service of Oklahoma ("PSO") case. 45 Another example is the NPSC
 6              in consolidated Docket Nos. 91-5032 and 91-5055. In that case the NPSC stated the
 7              following:
 8
 9                  Since NPC has no terminal salvage and cost of removal experience for steam
10                     and combustion turbine generating units, Mr. Ferguson [the utility
11                     witness] relied on demolition studies of other utilities, adjusted for the
12                     expected inflation between the study date and date of removal, in
13                     determining his recommended rates ....
14
15                  Mr. Pous criticized Mr. Ferguson for applying inflation to the cost of removal
16                     or demolition studies without also taking into consideration other factors
17                     such as the potential sale of production facilities or increased labor
18                     productivity which might impact gross salvage or cost ofremoval....
19
20                  Mr. Pous' arguments regarding the unreasonableness of Mr. Ferguson's
21                     proposed net salvage factors for Steam Production Plant are persuasive. It
22                     is apparent that Mr. Ferguson has selected only a limited number of
23                     demolition studies and interpreted them in a manner to suwort his
24                     position without adequately considering all factors involved. ... (Emphasis
25                     added).
26
27              In another case, the Michigan Public Service Commission ("MPSC") in case No. U9493,
28              a Consumers Power Company case, stated the following regarding the incorporation of
29              future inflation in determining net salvage for production plant:
30
31                  The Commission finds that Consumer's arguments must be rejected for
32                     several reasons. First, contrary to Consumer's assertions, it is not clear
33                     from the Commission's definitions of salvage value and cost of removal
34                     that future inflation must be included in the net salvage used to calculate
35                     depreciation rates. In fact, a review of those definitions reveals that they
36                     are silent on that issue and make no provision for inclusion ofinflation....
37
38                  Finally, the Commission also agrees with Staff and ABATE that it is
39                     unreasonable to charge current ratepayers for future estimated costs of
40                     removal that are escalated for inflation...Although magnifying the costs,
          45
               OCC Cause No. 200800144.

                                                                                                      34
     1                Consumer's did not consider future technological changes that might
     2                reduce removal costs. For these reasons, the Commission finds that
     3                Consumer's proposal is not in the public interest. Future inflation should
     4                not be reflected in the terminal net salvage for steam production plant.
     5                (Emphasis added).
     6
     7        The concept underlying net salvage for depreciation purposes is to estimate a reasonable
     8        level of net salvage to include in current rates so that current customers will pay their fair
     9        share of any such costs. To assume that inflation is the only factor that impacts future
    10        cost of removal is simply wrong. Many areas of construction or demolition that entail
    11        potentially large costs are subject to technological changes and process improvements.
    12        For example, the demolition or toppling of large smoke stacks rather than taking such
    13        structures down brick by brick is one improvement. Thus, Mr. Spanos' focus solely on
    14        inflation distorts any credible results obtained from the analysis.
    15
    16   Q.   IS THERE ANOTHER SIGNIFICANT REASON WHY INFLATION AS
    17        PROPOSED BY THE COMPANY IS INAPPROPRIATE?
    18   A.   Yes. Current customers should pay their current cost in current dollars. Under ETI's
    19        proposal, customers would be forced to pay for future costs established at a future dollar
    20        level without any discounting back to current dollar levels. This is simply not a logical
    21        conclusion and is not an accepted practice in utility ratemaking. For example, when
    22        future inflation is taken into account in the establishment of external decommissioning
    23        fund payments for nuclear plants, not only is an inflation or escalation rate included in the
    24        overall calculation, but an earnings or discount rate is included as well. The earnings or
    25        discount rate is included in order to recognize time value of money that occurs between a
    26        dollar being spent or invested today and a dollar spent or invested at some point in the
I   27        future. ETI's total failure to recognize a discount rate is a fatal flaw in its proposal.
    28
~   29   Q.   WHAT DO YOU RECOMMEND FOR PRODUCTION PLANT NET SALVAGE?
    30   A.   I recommend a zero (0)-level of net salvage for steam production plant as a conservative

I   31        position. The Commission may find it appropriate to adopt a positive 5% or greater level
    32        of net salvage for steam generating facilities in recognition of: (1) the significant increase

I   33        in scrap metal prices that have occurred during the last 5-7 years due in part to the
    34        significant growth by the economies of China and India; and/or (2) recognition of

                                                                                                          35
 l             potential total sale of generating unit, or partial sale of used equipment as operable
2              equipment, rather than a sale as scrap value.
3
4    Q.        DID MR. SPANOS CONSIDER THE POTENTIAL THAT A POSITIVE NET
5              SALVAGE COULD BE OBTAINED EVEN THROUGH A DEMOLITION
6              PROCESS?
7    A.        No. Mr. Spanos stated that he "would be very surprised that there is much of a market for
8              someone to come in and buy it [a generating unit] for the scrap value and consider that to
9              be more than the cost they will have to dismantle it when they have eventually walked
10             away from that site.'.46
11
12   Q.        ARE YOU AWARE OF A RECENT SITUATION WHERE A DEMOLITION
13             CONTRACTOR PAID TO TAKE DOWN A POWER PLANT?
14   A.        Yes. Just last year the King Power Plant in Ft. Pierce, Florida was being demolished.
15             Even though the cost estimator developed a study that estimated a substantial cost to
16             demolish, the winning bid to demolish the plant was a negative $974,000. In other words,
17             a contract offered to lli!Y almost $1 million to get the salvageable equipment and scraps
18             material while demolishing the plant. The winning bid also included substantial costs for
19             the removal of asbestos at the old plant. 47
20
21   Q.        COULD TIDS BE A SITUATION WHERE A CONTRACTOR WAS JUST OUT
22             OF LINE WITH ms ESTIMATE?
23   A.        No. In fact, there were four bids where contractors were willing to lli!Y between $250,000
24             and $600,000 for the right to demolish the plant.48


25   Q.        IS THERE AN AFTER MARKET FOR EQUIPMENT THAT WAS DESIGNED
26
27   A.
               FOR OLDER POWER PLANTS?
               Yes. For example, the city of Traverse, Michigan, recently retired the 1940s vintage
                                                                                                                             I
28             Bayside generating station. As part of the demolition, a sugar cane grower from Central


          46
             Deposition of Mr. Spanos on March 25, 2010 in PUCT Docket No. 37690 at TR 91.
          47
             Several conversations with Mr. John Tompeck, Capital Project Engineer for the Ft. Pierce Utilities Authority.
          48
             Several phone conversations with John Tompeck Project Engineer for the King Generation plant demolition
               plant for the Ft. Pierce Utility Commission, Ft. Pierce, Florida.

                                                                                                                       36    I
                                                                                                                             I
 1             America came, dismantled the boiler and other equipment, and shipped it to Central
 2             America for on his sugar cane plantation.49 Moreover, when investor owned utilities
 3             demolish power plants, usable items are sold or transferred rather than scrapped.
 4
 5   Q.        ARE YOU AWARE OF OTHER EVIDENCE THAT EQUIPMENT AT
 6             DEMOLISHED POWER PLANTS CAN AND HAVE BEEN SOLD RATHER
 7             THAN CONSIDERED USABLE ONLY FOR SCRAP VALUE?
 8   A.        Yes.   A presentation was made at a decommissioning conference regarding Florida
 9             Power & Light Company's ("FPL") Palatka decommissioning project. One of the slides
10             in that presentation clearly notes under the heading                     Salvage/Sale that the
11             turbine/generator for Unit 1 at that station was sold.so 1bis fact was confirmed by FPL's
12             decommissioning documents.          In spite of an active "after market" for power plant
13             equipment, when it comes to presenting a proposal, Mr. Spanos believes that selling
14             pieces of equipment is unlikely because there are so many requirements as to perfectly
15             matching equipment.st In contrast to this false assumption, he is more than willing to
16             offer negative 15% to 32% values without any underlying support.
17
18   Q.        HOW HAVE THE ECONOMIES OF CHINA AND INDIA IMPACTED
19             DEMOLITION COST ESTIMATES?
20   A.        The dramatic expansion of these economies has resulted in substantial upward pressure
21             on scrap metal prices. Prices for scrap copper are now over $3.00 per pound, while in the
22             early 2000s the price was more in the $0.40 price per pound range. Indeed, ETI admits
23             that it obtained $0.5039 per pound for scrap iron in 2008 while it was only able to obtain
24             $0.0621 per pound back in 2003.s2 Since the demolition of a power plant produces large
25             quantities of copper, steel and other metals, the gross salvage associated with the sale of
26             scrap metal can exceed the cost of demolition.




          49
             Web article at http://www.tclp.org/news_details.php?id=l22, and discussions with Traverse City electric
               department personnel.
          so Response to AXM 6-93 in PUCT Docket No. 35763.
          51
             Deposition of Mr. Spanos on March25, 2010 at TR 89.
          52
             Response to Rose City 1-34.

                                                                                                                 37
 1   Q.      WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
 2   A.      On a standalone basis my recommendation results in an $11. 7 million reduction in annual
 3           depreciation expense based on plant as of December 31, 2008.

 4        5. Mass Property Life

 5           A. Introduction

 6   Q.      WHAT IS THE PURPOSE OF THE LIFE PORTION OF A DEPRECIATION
 7           ANALYSIS?
 8   A.      The purpose of a life analysis is to determine the "average service life" or ASL, the
 9           dispersion pattern and remaining life for each account or subaccount. This information is
10           necessary to properly perform the depreciation calculation. A longer ASL results in a
11           longer remaining life and therefore a lower depreciation expense. Alternatively, a shorter
12           ASL will reduce the remaining life and increase depreciation expense. The dispersion
13           pattern is also important, as it is critical in the overall selection process of the best fitting
14           results. The same ASL with different Iowa Survivor Curves also results in different
15           remaining lives, due to the remaining expected pattern of retirements.
16
17   Q.      WHAT ARE THE MAIN TOOLS UTILIZED IN PERFORMING LIFE
18           ANALYSIS?
19   A.      Life analysis is normally performed by actuarial or semi-actuarial analyses. Actuarial
20           analyses rely on aged data. In other words, when an item of property is retired, the age at
21           retirement is known. 1bis is the type of analysis performed by insurance companies
22           when developing life tables in order to establish premiums. Semi-actuarial analyses are
23           performed in instances in which the age of retired plant is not known.
24
25   Q.      PLEASE       PROVIDE         MORE        INFORMATION             REGARDING           HOW       A
26           DEPRECIATION ANALYST PERFORMS SUCH A LIFE ANALYSIS THAT
27           RELIES ON AN ACTUARIAL APPROACH.
28   A.      Aged data is gathered and analyzed. Aged data means that when an asset retires in 2008
29           we know that it originally went in service in 1968, and was 40 years old at the time of
30           retirement. When all the aged data in a group is statistically analyzed by actuarial
                                                                                                           38
 1   techniques a resulting Observed Life Table or OLT is developed that depicts the rate of
 2   retirement over the life of the group. The OLT starts at 100% surviving and declines
 3   from there as each year of age is obtained and retirements occur. Naturally, not all units
 4   retire at once; instead, the retirement dates are dispersed through time, creating a
 5   "dispersion pattern." In order to permit testing and smoothing of the results some
 6   standard or index must be used. The principal tool that a depreciation analyst uses for
 7   this aspect of the study is a set of "survivor curves." The industry standard and most
 8   extensively used curves are called the Iowa Survivor Curves. The name is derived from
 9   the fact that they were developed at Iowa State College in the 1930s.
IO
11   Often, the historical data base analyzed does not yield a complete OLT, one that fully
12   declines to 0% surviving. This means that the data set will produce an incomplete OLT
13   or a "stub curve." Also, the limited data base may include atypical or abnormal events
14   not reasonably anticipated to occur again during the remaining life at the same levels
15   reflected in the historical data.
16
17   The Iowa Survivor Curves are based on empirical studies of retirement "behavior" of
18   physical property. They are designed to predict the retirement patterns of the property
19   under study based on detailed past observations. The Iowa Survivor Curves make the
20   calculation of the ASL far more manageable and comparable; instead of making and
21   weighting a myriad of individual calculations that include each data point in the universe,
22   the analyst measures the area below the curve and uses an established equation or
23   standard curve to "solve" for the ASL. And, even ifthe data set is incomplete-which is
24   often the case -by properly choosing a closely fitting curve to the known data, the
25   analyst can better predict the behavior of the entire universe and calculate the ASL with
26   reasonable statistical accuracy, if a meaningful "stub curve" exists. The results of any
27   estimation are more reliable if 70% of an OLT is known and only 30% must be assumed,
28   than if only 10% of the OLT is known and 90% must be assumed.
29
30   Not surprisingly, choosing the survivor curve that provides the best fit to the data is
31   critical to the accuracy of the analysis. When fitting the curves to the OLT the analyst
32   must bear in mind that some data points-those that occur on the points of the graph that

                                                                                             39
 1        reflect the most significant level of plant exposed to retirement events-- are more
 2        important to the determination of the ASL and dispersion pattern than others. Further,
 3        the analyst cannot use the curves in isolation of other considerations. The analyst must
 4        incorporate such things as knowledge of the nature of the property being studied, an
 5        understanding of the causes of unusual events, recognition of changes or trends, and
 6        judgment when using the curves.        Also, the nature of survivor curves limits their
 7        usefulness. For instance, they are best suited to studies of homogeneous items that,
 8        because of their physical similarity and common exposure to retirement forces, can be
 9        expected to share common retirement characteristics. (By analogy: When an insurance
10        actuary performs a mortality/longevity study for life insurance purposes, the actuary does
11        not combine people and horses in the universe of data.) It is for that reason that I
12        criticized ETI's analyst for inappropriately applying the Iowa Survivor Curves to interim
13        retirements for generation plant. The items of generation plant involved in interim
14        retirements frequently are far from homogeneous.
15
16   Q.   HAVE YOU REVIEWED THE COMPANY'S MASS PROPERTY LIFE
17        ANALYSES?
18   A.   Yes, I have reviewed the Company's mass property life analyses. The main problem
19        with the analyses is that Mr. Spanos proposes ASLs with corresponding Iowa Survivor
20        Curves that are not the best fitting results for the actuarial analyses, even when the final
21        proposal is based on actuarial results. Mr. Spanos' selections for most accounts reflect a
22        bias toward artificially short ASLs. It is unreasonable and inappropriate to ignore the
23        best fitting life analyses without detailed and credible explanations. Mr. Spanos fails to
24        provide support for his questionable practice.

25   Q.   BASED ON YOUR REVIEW OF THE COMPANY'S LIFE ANALYSES AND
26        OTHER INFORMATION, ARE YOU RECOMMENDING ADJUSTMENTS?
27   A.   Yes. I recommend adjustments to 16 accounts or subaccounts. The recommendations, as
28        well as the Company's proposals for each of the accounts where a change is
29        recommended, are set forth in the table below.




                                                                                                   40
                              MASS PROPERTY LIFE SUMMARY

                                                          ETI              Cities            Difference based
                                                        Proposed       Recommended            on Plant as of
                                                                                                   12/31/2008
                Account Descrintion                   ASL Curve ASL            Curve
                                                                                             ASL       Imnact53

 350 Transmission Land Rights                          65      R4       95        R4         30         $183,605

 353 Transmission Station Equipment                    45      R2.5     52       R2.5         7       $1,462,347

 354 Transmission Towers                               50       S4      63        S4          13        $110,162

 355 Transmission Wood & Steel Poles                   55       R3      59       R2.5         4       $1,080,733

 356 Transmission Overhead Conductors                  53      R2.5      55      R2.5         2         $210,829

 360 Distribution Land Rights                          55       R4       85       R4         30         $120,195

 362 Distribution Station Equipment                    40      Rl.5     46        so          6         $783,405

 365 Distribution Overhead Conductors                  36      R0.5     39       S0.5         3       $1,103,876

 366 Distribution Underground Conduit                  50       R2       60       R3          10        $182,339

 368 Distribution Line Transformers                    29       so       32      L0.5         4       $1,478,940

 369 Distribution Services - Overhead                  27       L4       31       R3          4       $1,159,669

 390 General Structures & Improvements                 44      R2.5      53       R2          9         $299,763

 391.2 General Information Systems                      5       SQ       10       SQ          5       $1,423,792

 394 General Tools, Shop & Garage                      15       SQ       20       SQ          5         $187,514

 397 .1 General Communication Equipment                10       SQ       15       SQ          5         $167,904

 397.2 General Communication Equipment                 15       SQ       20       SQ          5       $1,136,473
        Microwave




53
     Impact estimated based on change in ALG remaining life due to ELG calculation by ETI.

                                                                                                                41
 1               The combined impact of the various adjustments I recommend results in a standalone
2                impact of an $11,091,546 reduction to annual depreciation expense, based on plant as of
3                December 31, 2008. 54

 4   Q.          HOW ARE THE ULTIMATE LIFE-CURVE SELECTIONS MADE?
 5   A.          From an actuarial standpoint, the best fitting life-curve selections are made by visually
6                matching the OLT to standardized Iowa Survivor Curves. Mathematical curve fitting is
 7               flawed when it assigns an equal level of significance to each point in the matching
 8               process. Indeed, Mr. Spanos' admits that even though he does perform mathematical
 9               curve fitting as a part of his analysis, he does not "view that to be the proper way to do
10               life analysis."55
11
12   Q.          IN THE VISUAL MATCH PROCESS, ARE ALL POINTS OF COMPARISON
13               EQUAL?
14   A.          No. Many of the points of comparison for an OLT may reflect dollar levels of exposures
15               that differ by a factor of 10,000 or more. Indeed, Mr. Spanos also notes, but does not
16               adequately implement in his analysis, that a "significant portion" of the curve exists as it
17               relates to the curve matching process. 56 In other words, the "head" or top of the curve and
18               possibly middle portions of the curve are more significant in the curve fitting process
19               than is the "tail" of the curve.
20
21   Q.          IN THE CURVE FITTING PROCESS, IS IT MORE IMPORTANT TO MATCH
22               THE POINTS ON THE OLT THAT REFLECT LARGER DOLLAR LEVELS OF
23               EXPOSURES THAN THOSE POINTS WHERE THE                              DOLLAR LEVEL IS
24               MUCH LOWER?
25   A.          Yes. It would be foolish to accept the results of a standardized life-curve that better fits
26               the results of the end or "tail" of the OLT rather than a life-curve combination that is a
27               better fit near the "head" or top and upper portions of the OLT. While it is desirable to
28               have close fitting results all along the OLT, this unfortunately does not occur for many


          S4   Id.
          ss Deposition of Mr. Spanos on April 25, 2010 at TR l 12.
          s6 Direct Testimony of Mr. Spanos at page 34.

                                                                                                          42
     l               accounts. Therefore, recognition of the dollar level of exposures at different points of the
     2               OLT is critical.


     3               This is significant, since as each new year of plant activity transpires, the OLT can and
     4               usually does change. However, the future changes will not occur equally to all portions
     5               of the OLT. In fact, it is unlikely, given the level of exposures near the "head" or top of
     6               the OLT, that the few years between depreciation studies would result in any appreciable
     7               movement of that portion of the OLT absent unusual events. The same cannot be said of
     8               the "tail" portion of the OLT, and potentially even the mid portion of the curve. If larger
     9               retirements transpire in older age intervals, or more dollars of exposures filter further
    10               down in the OLT without corresponding retirements, the mid portion or tail of the OLT
    11               can move significantly, based on only a few years of additional data. That is precisely
    12               why matching the "head" and other significant portions of the OLT is more important
    13               than matching the ''tail."
    14

    15               B. Account Specific Adjustments
    16
    17   Account 350.2
    18
    19   Q.          WHAT        DOES       THE   COMPANY         PROPOSE        FOR ACCOUNT           350.2 -
    20               TRANSMISSION LAND RIGHTS?
    21   A.          The Company proposes a 65-year ASL with a corresponding R4 dispersion pattern. 57
    22
I   23   Q.          WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
    24   A.          This is one of the accounts where Mr. Spanos based his proposal on judgment, the nature
I   25               of the plant and equipment, the previous estimate for this Company and a general
    26               knowledge of service lives of similar equipment in other utilities. 58
I
              57
                   Exhibit JJS-1 page 52.
              58
                   Exhibit JJS-1 page 36.

                                                                                                              43
 1   Q.          DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
 2   A.          No. The Company's proposed 65-year ASL is artificially short. Land rights for
 3              transmission lines are difficult to obtain. The "not in my backyard" (''NIMB") syndrome
 4               is stronger than ever as it relates to new transmission right-of-way locations. Therefore,
 5               utilities will continue to rely on existing transmission land rights into the future absent
 6               unusual circumstances. In addition, all transmission right-of-ways remain in place until
 7              the utility releases its right to the land.59 Thus, the land rights can easily be in place for
 8               multiple life cycles of the equipment that rests upon such land rights. Indeed, the
 9               Company's proposed ASL for this account represents a period shorter than a single
10               maximum life cycle for the equipment that resides upon the land right. This is illogical on
11               its face. In other words, the Company proposes a 53-R2.5 life-curve combination for
12               Account 356 - Transmission Overhead Conductors & Devices. The maximum life, a
13               complete life cycle, for an investment with this life-curve combination is in excess of 95
14               years. Yet the Company proposes an ASL for easements of only 65 years.
15
16   Q.          HOW MANY EASEMENTS HAS THE COMPANY RETIRED IN ITS
17               RECORDED IDSTORY?
18   A.          None. The Company does not report a single retirement during the 50 years of retirement
19               activity reflected in its study. 60
20
21   Q.          WHAT DO YOU RECOMMEND?
22   A.          I recommend a 95-R4 life-curve combination. This ASL is conservative as it corresponds
23               approximately to only one maximum life cycle for overhead conductors and devices.
24               Obviously, additional investment has and will continue to be placed into service on the
25               same right-of-ways in the future, thus requiring an extension of my recommended ASL at
                 some point in the future.
26
                                                                                                                 I

          59
               Response to Rose City 13-5.
          60
               Exhibit JJS-1 pages 86 and 87.

                                                                                                           44
     1   Q.        WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
     2   A.        My recommendation of a 95-year ASL on a standalone basis results in a $183,605
     3             reduction in depreciation expense based on plant in service as of December 31, 2008.
     4
     5   Account 353
     6
     7   Q.        WHAT        DOES       THE   COMPANY        PROPOSE       FOR     ACCOUNT         353   -
     8             TRANSMISSION STATION EQUIPMENT?
     9   A.        The Company proposes a 45-R2.5 life-curve combination. 61
    10
    11   Q.        WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
    12   A.        This is an account where Mr. Spanos did not rely to any extent on the statistical analysis
    13             he performed on the historical data. 62 This is an account where Mr. Spanos relied on his
    14             standard statement of judgment, nature of the plant, previous estimates, and similar lives
    15             for other electric companies. 63
    16
    17   Q.        DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
    18   A.        No. The Company's proposal understates the realistic life expectancy for this account;
    19             therefore, I recommend a 52-R2.5 life-curve combination as a better representation of the
    20             life expectancy for this investment.
    21
    22   Q.        WHAT IS THE BASIS FOR YOUR RECOMMENDATION?
    23   A.        First, the historical actuarial analysis does provide some useful information. While Mr.
    24             Spanos apparently discounted the Company specific activity, it is clear that the Company
    25             has substantial levels of investment that have already exceeded the Company's proposed

I   26
    27
                   short ASL. Indeed, a better curve fit to the meaningful or significant portion of the data
                   indicates that a longer ASL is a better representation of the historical data than is the

I   28
    29
                   Company's proposed 45-year life. In fact, as shown in the graph below, the 52-year ASL
                   I recommend is a superior fit to the Company's data.

              61
                 Exhibit JJS-1 page 52.
              62
                 Exhibit JJS-1page33.
              63
                 Id., at page 34.

                                                                                                           45
                                                    ENTERGY TEXAS
                                  353-TRANSMISSION STATION EQUIPMENT(1984)

                           100




                             90
    (f)
    0::         ....c:
    g            Q)
                ....
                (.)
                             80
    >
    0::
                Q)
                a.
    :::>
    (f)


                             70



                             60
                                  0.5         8.5          16.5          24.5          32.5          40.5          48.5
                                        4.5         12.5          20.5          28.5          36.5          44.5          52.5
                                                                           AGE (YEARS)
                                                             Actual                     52R2.5         __..,_ 45R2.5




I                        In addition, the Company's historical data reflects retirement activity associated with
2                     recent hurricanes, thus resulting in an artificially short life indication even based on the
3                        Company's actuarial analysis. Next, a review of Mr. Spanos' industry database indicates
4                        that a longer ASL is warranted than the 45-year value he proposed. In fact, the mean,
5                        median and mode for his industry database all exceed 45 years, even when taking into
6                        account some unusually low values associated with cooperatives or old studies reflected
7                        in that database. 64 Mr. Spanos' notes also support something longer than a 45-year ASL.
8                        For example, Mr. Spanos' notes associated with substations specifically state "about 50

           64
                Response to Rose City 1-1 7 Attachment.

                                                                                                                                 46


                                                                                                                                      I
                    years. " 65 Indeed, the notes further identify the Company has a policy of cradle to grave
     2              accounting for its transformers, which should have indicated a longer ASL compared to
     3              the industry average since many utilities actually retire transformers when they move
     4               such equipment from one location to another. In addition, while Mr. Spanos' notes
     5               indicate that there is an expectation for a shorter lives in the future for transformers, this
     6              is an argument that has been utilized in the industry for the past 20 or 30 years, yet the
     7               industry has demonstrated increasing life expectancy for substation equipment as more
     8              empirical data has been obtained. Therefore, the 52-year ASL is more indicative of the
     9              Company's actual experience, better reflects industry expectations, and is more
    10              representative of the type of equipment in the account.
    11
    12   Q.         WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
    13   A.         My recommendation of a 52-year ASL on a standalone basis results in a $1,462,347
    14              reduction to depreciation expense based on plant in service as of December 31, 2008.
    15
    16   Account354
    17
    18   Q.         WHAT        DOES      THE      COMPANY         PROPOSE        FOR      ACCOUNT         354   -
    19              TRANSMISSION TOWERS?
    20   A.         The Company proposes a 50-S4 life-curve combination. 66
    21
    22   Q.          WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
    23   A.         This is an account where the historical data is not relied upon and Mr. Spanos reverts to

I   24
    25
                     his generalized statement referring to judgment and other information.


    26   Q.         DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
    27   A.         No. I recommend a 63-S4 life-curve combination.

I
I             65
                   Response to Rose City 1-15 Addendum page 46.
              66
                   Exhibit JJS-1 page 52.

                                                                                                                 47
 1   Q.        WHAT IS THE BASIS FOR YOUR RECOMMENDATION?
 2   A.        First, while the historical data provides an extremely short "stub curve", it does provide
 3             an indication for a long ASL given the very limited level of retirement activity that has
 4             transpired during over 50 years of data. 67 In addition, Mr. Spanos' industry database
 5             indicates a mean, median and mode of 63, 65 and 65 years, respectively. 68 Indeed, the
 6             industry data that would have formed possibly a major portion of Mr. Spanos'
 7             'judgment" indicates that the use of a 50-year or lower ASL is very limited. Therefore,
 8             all indications of available data indicate that a value in the mid 60-year range is by far
 9             superior to the Company's proposed 50-year ASL. Moreover, the Company proposed a
10             55-year ASL for Account 355 - Transmission Poles. On a predominant basis, the
11             industry recognizes that transmission towers have longer expected ASLs than do
12             transmission poles. In this case, Mr. Spanos also failed to take this relationship into his
13             judgmental decision making process.
14
15   Q.        WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
16   A.        My recommendation of a 63-year ASL on a standalone basis results in a $110,162
17             reduction to depreciation expense based on plant as of December 31, 2008.
18
19   Account 355
20
21   Q.        WHAT          DOES    THE      COMPANY      PROPOSE        FOR     ACCOUNT         355   -
22             TRANSMISSION POLES AND FIXTURES?
23   A.        The Company proposes a 55-R3 life-curve combination. 69
24
25   Q.        WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
26   A.        This is another account where Mr. Spanos claims to have relied on the statistical actuarial
27             results. 70



          67
             Exhibit JJS-1pages99 and 100.
          68
             Response to Rose City 1-17 Attachment.
          69
             Exhibit JJS-1page52.
          70
             Exhibit JJS-1 page 33.

                                                                                                        48
     1   Q.          DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
     2   A.         No. The Company's proposal is artificially short; therefore, I recommend a 59-R2.5 life-
     3               curve combination.
     4
     5   Q.          WHAT IS THE BASIS FOR YOUR RECOMMENDATION?
     6   A.         As shown in the graph below, my recommendation results in a better fit to the OLT in the
     7              significant portion of the curve that Mr. Spanos referenced in his testimony. Indeed, Mr.
     8              Spanos sacrificed a better fitting relationship during periods beginning around age 8 years
     9              in order to strive for a better match during the age intervals of approximately 25 years
    10              through 35 years. The problem with Mr. Spanos' election to discount the earlier portion
    11              of the curve in an effort to match a later portion of the curve sacrifices exposures in the
    12              $40-$70 million range for better fitting exposures in the $15-$40 million range. 71 As can
    13              be seen in the graph be]ow, my recommendation is a superior fit during the first
    14              approximate 24 years of age.




I



              71
                   Exhibit JJS-1pages104-105.

                                                                                                            49
                                                    ENTERGY TEXAS
                                   355 - TRANSMISSION POLES AND FIXlURES (1954)

                           100




                            90
    en
    a:::
    0
    >
                 -
                 c::
                 Q)
                  ....
                  (.)


    ~            Q)
                 0...
    ::::>
    en                      80




                            70
                                 0.5          8.5          16.5          24.5          32 .5          40.5          48.5
                                        4.5         12.5          20.5          28.5           36.5          44.5          52.5
                                                                            AGE (YEARS)
                                                                  Actual                  59R2. 5        __..._ 55R3



1                        In addition, Mr. Spanos' notes indicate that new poles are steel and concrete, thus
2                        indicating a longer life expectancy in the future than reflected in the historical data,
3                        which reflects a higher level of wood poles. While Mr. Spanos reflected such information
4                        in his notes, he apparently failed to take that into consideration in his undocumented
5                        decision making process. 72 Otherwise, he would have proposed a longer ASL. Thus, from
6                        a curve-fitting process, and taking into account the limited additional information
7                        provided by the Company, a longer ASL than the 55-year life proposed by the Company
8                        is warranted. Analysis of historical data and supplemental information better supports a
9                        59-year ASL.


            72
                 Response to Rose City 1-15 Addendum at page 46.

                                                                                                                                  50


                                                                                                                                       I
     1
     2   Q.         WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
     3   A.         My recommendation for a 59-year ASL on a standalone basis results in a $1,080,733
     4              reduction to depreciation expense based on plant in service as of December 31, 2008.
     5
     6   Account 356
     7
     8   Q.         WHAT         DOES       THE   COMPANY          PROPOSE    FOR     ACCOUNT        356   -
     9              TRANSMISSION OVERHEAD CONDUCTORS?
    10   A.         The Company proposes a 53-R2.5 life-curve combination. 73
    11
    12   Q.         WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
    13   A.         For this account, the Company relies on Mr. Spanos' claim relating to a good to excellent
    14              indication from the statistical analyses. 74
I   15
    16   Q.         DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
I   17   A.         No. The Company's proposal understates the realistic ASL for this account. Therefore, I
    18              recommend a 55-year ASL with a corresponding R2.5 Iowa Survivor Curve. As shown in
    19              the graph below, both Mr. Spanos' proposal and my recommendation are both good fits
    20              of the data for approximately the first 27 years of age. At that point the Company's
    21              proposal begins to deviate from the OLT until approximately 35 years of age and
    22               understates the expected ASL. Thus, both curves are good fits through the most
    23               significant portion of the curve, but the longer ASL continues the good fit through most

I   24
    25
                     of the remaining portion of the OLT including portions of the curve that are still
                     significant. Another consideration for a somewhat longer ASL is that to the extent any

I   26
    27
                     retirement activity associated with major hurricanes that occurred in recent periods is
                     reflected in the Company's data, it would understate the expected ASL for the remaining

l   28
    29
                     investment. Therefore, a modest increase from what the Company has proposed in the
                     expected ASL is warranted at this time.


              73
                   Exhibit JJS-1 page 52.
              74
                   Id., at page 33.

                                                                                                           51
                                                 ENTERGY TEXAS
                        356 - TRANSMISSION OVERHEAD CONDUCTORS AND DEVICES (1954)

                        100



                          90
     C/)
     a:
     0
                ...c:
     >          Q)
                ,_
                0         80
     >
     a:
                Q)
                a..
     ::>
     C/)


                          70



                          60
                               0.5         8.5          16.5          24.5           32.5           40.5          48.5
                                     4.5         12.5          20.5          28 .5          36 .5          44.5          52.5
                                                                        AGE (YEARS)
                                                          Actual         __..._ 55R2. 5               -6---       53R2. 5




1   Q.              WHAT IS THE IMP ACT OF YOUR RECOMMENDATION?
2   A.              My recommendation for a 55-year ASL results in a $210,829 reduction to the Company' s
3                     annual depreciation expense based on plant in service as ofDecember 31, 2008.


4   Accounf 360
5
6   Q.                WHAT      DOES        THE         COMPANY               PROPOSE                FOR          ACCOUNT       360   -
7                     DISTRIBUTION LAND RIGHTS?
8   A.                The Company proposes a 55-R4 life-curve combination. 75

           75
                Exhibit JJS-1 page 51.

                                                                                                                                      52
     I   Q.          WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
     2   A.          Given that there have been no retirement activity reflected in the Company's historical
     3               database, this is an account where the Company relied on judgment and other undefined
     4               parameters.
     5
     6   Q.          DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
     7   A.         No. The same situation as discussed for Account 350 - Transmission Land Rights also
     8              pertains to Distribution Land Rights. The Company's selection would have land rights
     9              retiring long before the end of a single life cycle is reached for various other distribution
    10               accounts. Thus, on its face, the Company's proposal is illogical. Therefore, I recommend
    11              a 85-R4 life-curve combination, taking into account land rights must exist for at least one
    12              complete life cycle relating to the investment that resides upon it. As time passes this
    13              estimate will have to be expanded in recognition that retirements will not occur as
    14              additional new plant is placed on the same land rights and that new investment must also
    15              complete its life cycle.
    16
    17   Q.         WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
    18   A.         My recommendation for an 85-year ASL results in a $120,195 reduction in depreciation
    19              expense based on plant as of December 31, 2008.
    20
    21   Account 362
    22
    23   Q.         WHAT        DOES       THE      COMPANY           PROPOSE         FOR      ACCOUNT   362   -

I   24
    25   A.
                    DISTRIBUTION STATION EQUIPMENT?
                    The Company proposes a 40-Rl.5 life-curve combination. 76

I   26
    27   Q.         WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?

I   28
    29
         A.         This is an account where the Company relied on what appeared to be a good to excellent
                     statistical indication from its statistical analysis of historical data. 77


              76
                   Exhibit JJS-1page53.
              77
                   Id., at page 34.

                                                                                                               53
 1   Q.        DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
 2   A.        No. The Company's proposed ASL is too short for the investment in this account.
 3             Therefore, I am recommending a 47-Rl life-curve combination.
 4
 5   Q.        WHAT IS THE BASIS FOR YOUR RECOMMENDATION?
 6   A.        A review of the historical OLT identifies two significant retirement periods that appear to
 7             be out of line. In particular, the Company experienced its second highest retirement level
 8             during the age interval of zero (0) to 0.5 year. 78 It is unusual to have such significant
 9             levels of infant mortality in comparison to older aged equipment. Indeed, the vast
IO             majority of this infant mortality incurred in 1954. 79 No other infant mortality of this
11             magnitude has transpired in the subsequent 54 years. Therefore, proper judgment should
12             have recognized this event as an outlier and normalized it in the database. The reality is
13             that utilities, absent unusual events, are not expected to purchase and install equipment
14             that is expected to fail immediately upon installation to any great extent. Thus, the
15             Company's historical OLT reflects an artificial reduction at an early time frame given
16             that such data is being used as a predictive tool for future expectations.


17             The largest level of retirement activity during any age interval occurred beginning at age
18             interval 6.5 years. 80 This annual level of retirement activity is approximately ten times the
19             level of retirement activity in the age intervals immediately preceding or following.
20             Again, this is the type of activity that should have caused an analyst to question the
21             validity of the resulting OLT as a basis for projecting future expectation for the remaining
22             investment. Indeed, this single age bracket yielded the highest retirement ratio through
23             the first 70 years of age.81 The impact of this single age bracket produced an atypical and
24             noticeable decline in the OLT as set forth in the graph in the Company's depreciation
25             study. 82 Events of this magnitude warrant further investigation, yet Mr. Spanos'
26             testimony, exhibits, workpapers and site visit notes make no reference to any specifics
27             regarding this retirement activity. Based upon further investigation it has been determined

          78
             Exhibit JJS-1 page 126.
          79
             Response to Rose City 13-7.
          80
             Exhibit JJS-1page126.
          81
             Id., at pages 126-127.
          82
             Id., at page 125.

                                                                                                          54


                                                                                                                I
     I        that $4.8 million of the $5.4 million was a retirement during age interval 6.5 years and
     2        relevant to a 8MVA stored magnetic energy superconductor unit located at a substation.
     3        The Company could not provide any support for why a retirement of this magnitude for
     4        this type of equipment is expected to reoccur on a similar basis in the future. 83 Therefore,
     5        the impact of what is a single, but large, unusual event should have been normalized in
     6        the Company's analysis. Indeed, Mr. Spanos, who claims constant reliance on judgment,
     7        apparently failed to even recognize that his own database of other utilities would have
     8        indicated that his proposed 40-year ASL for this account was well below the mean,
     9        median or mode for his industry range. 84 This discrepancy between ETI and the industry
    10        should have resulted in this transaction being adjusted prior to the curve fitting process
    11        had proper judgment been employed.
    12
    13        As set forth in the graph below, I have normalized only the outlier at the 6.5 age
    14        interval. 85 As can be seen, my recommended 46-SO life-curve combination is a superior
    15        or equal fit to all data points when compared to Mr. Spanos' proposal. Moreover, my
    16        recommendation better matches Mr. Spanos' industry data and is consistent with the
    17        cradle to grave type accounting employed by the Company for transformers and other
    18        major equipment at substations, as identified in Mr. Spanos' site visit notes. 86 My
    19        recommendation is conservative given the fact that the curve matching process still
    20        incorporates atypical hurricane activity that should have also been normalized.




I
I
I
         83
            Response to Rose City 1-2 13-18.
         84
            Response to Rose City 1-16 Attachment even prior to the elimination of obvious outliers in Mr. Spanos' own
              database.

'        as Reflects 1979-2008 Experience band to address infant mortality issue.
         86
            Response to Rose City 1-15 Addendwn at pages 46 and 48.

                                                                                                                   55
                                                   ENTERGY TEXAS
                               362 - DISTRIBUTION STATION EQUIPMENT (Normafized)
                        100


                          90


     en
     g-
     a::                  80
                c::
                Q)
                0
     >
     a:: a.
                ~
                Q)

     ::::>                70
     en

                          60                                                                                                                        I
                          50
                               0.5         8.5          16.5          24.5           32.5          40.5          48.5          56.5          64.5
                                     4.5         12.5          20.5          28 .5          36.5          44.5          52.5          60.5

                                                                        AGE (YEARS)
                                                          Actual                     46R1.5          __..__ 40R1.5




1   Q.                WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
2   A.                My recommended 46-year ASL results in a $783,405 reduction to annual depreciation
3                     expense based on plant as of December 31, 2008.


    Account 365
4
5
                                                                                                                                                    I
6
7
    Q.                WHAT      DOES        THE
                      DISTRIBUTION OVERHEAD CONDUCTORS?
                                                        COMPANY               PROPOSE               FOR          ACCOUNT              365      -
                                                                                                                                                    I
8   A.                The Company proposes a 36-R0.5 life-curve combination. 87
                                                                                                                                                    1
           87
                Exhibit JJS-1page53.

                                                                                                                                              56
     I
     2   Q.          WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
     3   A.          This is an account where the Company relied heavily on the results of its statistical
     4               analysis. 88
     5
     6   Q.          DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
     7   A.          No. The Company's proposal is artificially short. Therefore, I recommend a 39-S-0.5 life-
     8               curve combination. The Company's historical data included $2.8 million of unusual
     9               retirement activity in the age interval 0.5 that occurred in 2008, the year in which
    10               Hurricane Ike hit. 89 The retirement activity at age intervals 0.5 is significantly greater
    11               than any other time frame and is atypical in nature. Therefore, at a minimum, the OLT
    12               would need to be normalized for such activity. As shown in the graph below, my life-
    13               curve combination is a better match to the historical data minimally for the first 30 years,
    14               and then again beginning at approximately 44 years of age. If the remaining retirements
    15               associated with recent hurricane activity were also removed from the data, it would raise
    16               the OLT and make my recommendation even a better fit than set forth in the graph
    17               below.




I
I
I

'             88
              89
                   Id., at page 34.
                   Response to Rose City 13-11.

                                                                                                               57
                                              ENTERGY TEXAS
              365- DISTRIBUTION OVERHEAD CONDUCTORS & DEVICES (Normalized)

                          100
                                  :-..
                            90
                                         ~~              ~
                            80
                                                         ~
                            70                               ~~
     Cl)
     0::                                                         ~
                                                                      ~
                                                                        ..,
                  .+J
     0            cQ)       60
     > e
     6;
     ::::>
     Cl)
                  Q)
                  a..       50

                            40

                            30
                                                                              '   .....

                                                                                  ~

                                                                                          ~   ~



                            20
                                                                                              ~~        a_

                                                                                                    ~
                            10     111 111 111 111 Ill 111 Ill 111 111 111 111 111 111 111              ~~   JUI 111 111 111


                                 0.5         8.5       16.5    24.5    32.5    40 .5    48.5    56 .5    64.5
                                       4.5         12.5    20.5    28.5    36.5     44.5    52.5     60.5

                                                                          AGE (YEARS)

                                                    I        Actual       - - - 398-0.5           ___._ 36R0.5
                                                                                                                 I
1                       Other considerations supporting a longer ASL are the fact that the only item of
2                       information referenced by Mr. Spanos in his site notes was that if poles go down,
3                       conductors may not be damaged and thus still in use. 90 All else equal, this would imply
4                       that an ASL for conductors should be approximately as long as poles, if not longer. It
5                       should be noted that my 39-year ASL recommended for conductors is one year shorter
6                       than what Mr. Spanos has recommended for poles. Finally, a review of Mr. Spanos'
7                       industry data would indicate that even a 39-year ASL is on the shorter side of life
8                       expectancy. Thus, in conjunction with my life recommendation, the Commission should
9                       also order the Company to perform a detailed analysis to normalize the impacts of major
1O                      hurricanes that occurred in the 2005 through 2008 era for use in the next depreciation
             90
                  Response to Rose City 1-15 Addendum at page 49.

                                                                                                                           58
     1             study. Overall, my recommended 39-year ASL is conservative, considering actual
     2             historical data even before normalization for all hurricane activity.
     3
     4   Q.        WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
     5   A.        My recommendation for 39-year ASL results in a $1,103,876 reduction in depreciation
     6             expense based on plant as of December 31, 2008.
     7
     8   Account 366
     9
    IO   Q.        WHAT       DOES       THE      COMPANY        PROPOSE        FOR        ACCOUNT   366   -
    11             DISTRIBUTION UNDERGROUND CONDUIT?
    12   A.        The Company proposes a 50-R2 life-curve combination. 91
    13
    14   Q.        WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
    15   A.        This is an account where the Company did not rely on the statistical analysis it
    16             performed, but rather relied on unidentified judgment and other factors. 92
    17
    18   Q.        DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
    19   A.        No. First, it must be noted that the existing ASL for this account is 60 years. Thus, the
    20             Company is proposing a 10-year reduction based on undefined judgment. A review of the
    21             data indicates unusually high levels of retirement activity at low age intervals, without
    22             any explanation. 93 Substantial amounts of these early age retirements are associated with
    23             underground plastic conduit and pads for transformers. These are not the type of

I   24
    25
                   investments that one would normally anticipate retiring at early ages, absent unusual
                   circumstances. Moreover, industry experience would indicate that even a 50-year ASL is
    26             artificially short. Indeed, Mr. Spanos' industry data, which is skewed with several very
                                                                                                           94
    27             short lives, still yields mean, median and mode values of approximately 55-60 years.
    28             There is no logical explanation or documentation presented by the Company that


              91
                 Exhibit JJS-1 page 53.
              92
                 Id., at page 34.
              93
                 Response to Rose City 13-12 through 13-15.
              94
                 Response to Rose City 1-17.

                                                                                                           59
 1               warrants a reduction from the existing 60-R3 life-curve combination. Therefore, I
 2               recommend retention of the existing ASL, which is more in line with the type of
 3               investment reflected in this account.
 4
 5   Q.          WHAT IS THE IMP ACT OF YOUR RECOMMENDATION?
 6   A.          My recommended 60-year ASL results in a $182,339 reduction to depreciation expense
 7               based on plant as of December 31, 2008.
 8
 9   Account 368
10
11   Q.         WHAT         DOES       THE       COMPANY      PROPOSE    FOR     ACCOUNT        368   -
12              DISTRIBUTION LINE TRANSFORMERS?
13   A.         The Company proposes a 29-SO life-curve combination.95
14
15   Q.         WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
16   A.          For this account the Company relied on what it believed to be a good or excellent
17               statistical fit for the historical data. 96
18   Q.          DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
19   A.         No. The Company's proposal results in one of the shortest ASLs for any utility in the
20               industry. Therefore, at a minimum, I recommend increasing the ASL to 32 years with a
21               corresponding L0.5 Iowa Survivor Curve.
22
23   Q.          WHAT IS THE BASIS FOR YOUR RECOMMENDATION?
24   A.          First, a 31-L0.5 life-curve combination represents as good a fit to the OLT as does the
25               Company's proposal. Indeed, given the type of investment and other considerations, a 31-
26               L0.5 life-curve combination is a more realistic expectation for the investment in this
27               account. However, some of the other items of information exist that require some
28               additional level of increase in ASL. Those other items of information are the existing
29               ASL, the impact of hurricane related retirements, and industry information. The existing


          95
               Exhibit JJS-1 page 53.
          96
               Id., at page 34.

                                                                                                       60
     1         ASL for this account is 39 years, thus the Company is proposing a value 10 years shorter
     2         than the existing level. Even if this was a reasonable prediction, which it is not, a degree
     3          of gradualism may be warranted.
     4

     5          More significant to the concept for a longer ASL than proposed by the Company is the
     6          fact that the Company has included significant retirement activity associated with
     7         hurricane-related recent events. Normalization of the data to remove hurricane activity
     8         would result in raising the OLT from its current position, thus resulting in a longer ASL.
     9         Indeed, just removing the 2008 retirement activity for ages 0.5 year through 5.5 years,
    10         corresponding to just the 2002-2007 vintage additions, increases the "head" or top
    11         portion of the survivor curve by approximately 0.6 of a percentage point. This level of
    12         increase is meaningful.
    13
    14         In addition, Mr. Spanos states in his site visit notes that the Company has historically
    15         overloaded its line transformers. This is not a typical practice for an extended period of
    16         time and thus, future life expectancy should be longer than that experienced historically. 97
    17          Yet another consideration is the fact that Mr. Spanos' industry database indicates that a
    18         29-year ASL would be basically at the extreme low end of the industry range. Even
    19         retaining the unusually low values in Mr. Spanos' database, the mean, median and mode
    20         would all be in the upper 30 to 40 year range, or more in line with the existing ASL.
    21
    22          Some minimal increase in the ASL above the 31-year ASL (that is as good a fit to the
    23         historical data as is the Company's proposal) is warranted in light of industry data, the
    24          Company's inappropriate historical actions of overloading transformers, the existing
    25          ASL, and the inclusion of hurricane activity in the historical data. Therefore, I am

I   26
    27
                recommending a minimal incremental increase of one additional year as a conservative
                estimate in favor of the Company. I further recommend that the Commission order the

I   28
    29
                Company to demonstrate the prudence of its continued operation of transformers above
               maximum ratings, or that it is no longer performing such unusual activity, by the time it
    30          files its next depreciation study.

         97
              Response to Rose City 1-15 Addendum at page 49.

                                                                                                         61
 1   Q.        WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
 2   A.        My recommendation for a 32-L0.5 life-curve combination results in a $1,478,940
 3             reduction to depreciation expense based on plant in service as of December 31, 2008.
 4
 5   Account 369
 6
 7   Q.        WHAT       DOES         THE   COMPANY       PROPOSE        FOR     ACCOUNT         369   -
 8             DISTRIBUTION SERVICES?
 9   A.        The Company proposes a 27-U life-curve combination for both underground and
10             overhead services. 98
11
12   Q.        WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
13   A.        This is one of the accounts where Mr. Spanos relied extensively on his actuarial analysis
14             for his proposal. 99


15   Q.        DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
16   A.        No. A 29-year ASL represents basically the shortest ASL in Mr. Spanos' industry
17             database of approximately 60 values. The only few values that are lower correspond to a
18             Canadian utility, a cooperative and a utility that has not had its proposed ASL tested in a
19             fully litigated proceeding. 100 Moreover, the historical data relied upon by Mr. Spanos
20             incorporates the impact of recent severe hurricane activity, which helps produce the
21             proposed artificially short ASL.
22
23   Q.        WHAT DO YOU RECOMMEND?
     A.
24
25
               I recommend a very conservative estimate of a 31-year ASL with an R3 Iowa Survivor
               Curve. Initial review of Mr. Spanos' proposal raises concern from not only the short ASL
                                                                                                             I
26             standpoint, but also from the standpoint of the unusual "L4" dispersion pattern. Mr.
27             Spanos' database of other utilities indicates a 40-45 year ASL is indicative of average

          98
             Exhibit JJS-1 page 53.
          99
             Id., at page 34.
          100
              Response to Rose City 1-17.

                                                                                                        62


                                                                                                             J
     1         industry expectations. 101 In other words, the industry indicates a longer ASL than the
     2         existing 36-year level, definitely not a reduction to the 27-year level as proposed by the
     3         Company. Next, review of Mr. Spanos' industry database further raises concern
     4         regarding the proposed "L4" Iowa Survivor Curve. In this existence, Mr. Spanos'
     5         judgment relating to what he has observed from the industry and the type of plant in this
     6         account should have resulted in further investigation. Indeed, not a single other industry
     7         value relies on "L4" dispersion, or for that matter any "L" pattem. 102
     8
     9         Another consideration that is not addressed by Mr. Spanos is the movement towards more
    10         underground rather than overhead services. As reaffirmed by Mr. Spanos' industry
    11         database, underground services are generally expected to have a longer ASL than
    12         overhead services. l03 The percent investment in underground services has grown faster
    13         than for overhead services in the last I 5 years. 104 This fact should have also indicated a
    14         longer ASL. Finally, the fact that the Company's data includes hurricane related
    15         retirements further demonstrates that a longer ASL than indicated by the OLT is
    16         appropriate.
    17
    18         In order to remain conservative, I am recommending splitting the difference between the
    19         existing 36-year ASL and the 27-year ASL proposed by the Company, which yields a 31-
    20         year ASL. Such a value still leaves the Company at the very low end of the industry
    21         range, well below industry averages, and the existing ASL. I also recommended a "R3"
    22         Iowa Survivor Curve, which corresponds to the most frequently used curve in Mr.
    23         Spanos' database. In conjunction with my ASL recommendation, I further request that

I   24
    25
               the Commission order the Company to provide a detailed analysis as to why its historical
               database gives indications of artificially short ASLs and what portion of such lower ASLs

I   26         is due to the inclusion of recent hurricane related activity.




         101 Id.
r        102 Id.
         103 Id.
         104


I            Exhibit JJS-1 pages 289-291.

                                                                                                        63
 1   Q.         WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
 2   A.         My recommendation for a 31-R3 life-curve combination results in a $1,159,669 reduction
 3              to depreciation expense based on plant as of December 31, 2008.
 4
 5   Account 390
 6
 7   Q.         WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 390 - GENERAL
 8              PLANT STRUCTURES AND IMPROVEMENTS?
 9   A.         The Company proposes a 44-R2.5 life-curve combination. 105
10
11   Q.         WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
12   A.         The Company relies on the results of its statistical actuarial analysis for this account. 106
13
14   Q.         DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
15   A.         No. This is an account that requires special investigation. This account varies throughout
16              the industry because some utilities only rent facilities and have leasehold improvements
17              reflected in this account, while other utilities own the actual structure including the
18              interior components as well as roofs and other systems. The life expectancy for leasehold
19              improvements is much shorter than the life expectancy of an entire office building or
20              warehouse that is owned rather than leased. ETI owns most of its buildings. 107
21
22   Q.         WHAT DO YOU RECOMMEND?
23   A.         I recommend a 53-R2 life-curve combination as a conservative value. First, it must be
24              noted that a dramatic decline in the OLT as set forth on Exhibit JJS-1 page 176 is a result
25              of an internal decision by the Company to retire, for accounting purposes only, a portion
26              of its corporate headquarters. The investment in that building was subsequently
27              transferred to non-utility plant. In other words, the facility was not actually retired, but
28              reflects an accounting transaction between the regulated and non-regulated portions of



          105
              Exhibit JJS-1page53.
          106
              Id., at page 34.
          107
              Response to Rose City 1-41.

                                                                                                                64
     l              the Company's business. 108 This type of transaction is atypical and should not negatively
     2              affect current customers through the depreciation process. Relying on the remainder of
     3              the OLT, but eliminating this unusual transaction, would require a substantial increase in
     4              ASL.
     5
     6              In addition, the majority of the investment in this account is associated with office
     7              buildings and other structures that the Company owns rather than leases. 109 Office
     8              structures, warehouses and similar facilities can normally have life expectancies
     9              approaching 75 to 100 years or more. Taking into account that the investments still
    10              require a replacement of air conditioning systems, roofs and others components would
    11              reduce the dollar-weighted ASL. Mr. Spanos' industry database indicates numerous
    12              ASLs for investment in this account that still exceed 50 and even 60 years. In addition,
    13              Mr. Spanos' site visit notes state that buildings are generally "concrete slab with steel
    14              structures on top."uo Steel buildings on concrete slabs can easily be expected to achieve
    15              50 or even 60 years on a dollar-weighted basis. Therefore, my recommended 53-year
    16              ASL is conservative in favor of the Company.
    17
    18   Q.         WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
    19   A.         My recommended 53-R2 life-curve combination results in a $299,763 reduction to
    20              depreciation expense based on plant as of December 31, 2008.
    21
    22   Account 391.2
    23
    24   Q.         WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 391.2 - GENERAL
    25              INFORMATION SYSTEMS?
    26   A.         The Company proposes a 5-SQ life-curve combination, or a 5-year amortization
    27              period. 111




I             108
              109
              110
                  Response to Rose City 13-18.
                  Response to Rose City 1-41.
                  Response to Rose City 1-15 Addendum at page 149.
              111
                  Exhibit JJS-1 page 53.

                                                                                                            65
 I   Q.          WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
 2   A.          Mr. Spanos establishes the amortization period based on the anticipated life of the asset
 3               over which benefits will be realized. u 2 The amortization period is based on ''judgment
 4               which incorporates a consideration of the period during which the assets will render most
 5               of their service, the amortization period and service lives used by other utilities and the
 6               service life estimates previously used for the asset under depreciation accounting." 113
 7
 8   Q.          DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
 9   A.          No. The Company's proposal is artificially short; therefore, I recommend a IO-year
I0               amortization period. First and foremost, this is an account where the Company has
11               already experienced an acceleration of amortization expense given that many vintages are
12               already fully accrued, yet the plant is still in service. 114 What is clear is the 5-year
13               amortization clearly understates the expected useful life of the facility. Moreover, Mr.
14               Spanos' has failed to provide any judgmental basis that would render a 5-year
15               amortization period for this investment as realistic and appropriate.
16
17               Another consideration that recognizes the understatement of amortization period is Mr.
18               Spanos' reference to the period during which the asset will "render most of their service."
19               Service life or amortization period is not intended to capture "most" of the service life of
20               an asset, but the entire service life of the asset. Even if the "most" standard were
21               appropriate, Mr. Spanos has understated the reasonable amortization period for the
22               majority of the expected life. In addition, my recommend I 0-year amortization period is
23               consistent with what is the existing rate approved by the Commission in Docket No.
24               16705. Mr. Spanos' proposal cuts the existing IO-year amortization period in half. It is
25               therefore inappropriate from the standpoint of his stated basis. In addition, review of Mr.
26               Spanos' industry database further supports the use of the IO-year amortization period
27               rather than the proposed 5-year amortization period. In fact, the majority of the values
28               reported for information software systems in Mr. Spanos' database are IO years. No

          112
                Exhibit JJS-1 page 46.
          113   Id.
          114
                Exhibit JJS- l page 302.

                                                                                                            66
                 information software system was assigned a 5-year value in Mr. Spanos' database.
 2               Indeed, other utilities are employing values up to 15 years for major customer
 3               information software systems. Therefore, my recommendation to retain the existing 10-
 4               year amortization period is conservative and complies with Mr. Spanos' stated basis for
 5               his judgmentally derived proposal.
 6
 7   Q.          WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
 8   A.          My recommendation to retain the existing 10-year life would result in a $1,423,792
 9               reduction to amortization expense based on plant as of December 31, 2008. In addition, a
10               remaining life annual amortization rate should be set at 7. 7%.
11
12   Account 394
13
14   Q.          WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 394 - GENERAL
15               TOOLS, SHOP & GARAGE EQUIPMENT?
16   A.          The Company proposes a 15-year amortization period. 115
17
18   Q.          WHAT IS THE COMP ANY'S BASIS FOR ITS PROPOSAL?
19   A.          The Company's basis is the same as identified as above for Account 391.2.
20
21   Q.          DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
22   A.          No. The Company's amortization period is artificially short. Therefore, I recommend a
23               20-year amortization period for the investment in this account. First, it must be noted that
24               the existing depreciation life for the investment in this account is 20 years. Thus, Mr.
25               Spanos obviously did not rely on this particular item of information for his judgmental
26               approach even though it is one of the stated bases. Next, the investment in this account is
27               at the point of reaching the 15-year proposed amortization period, thus ifthe amortization
28               period is not extended the Company would be recovering through base rates a fully
29               recovered investment that has not been retired. 116


          115
                Exhibit JJS-1 page 53.
          116
                Id., at page 306.

                                                                                                          67
 1              The second item considered by Mr. Spanos referenced in his testimony is what other
 2              utilities are using. Again, Mr. Spanos' proposed 15-year amortization period falls short of
 3              his own industry database. Indeed, the predominant value Mr. Spanos reflects in his
 4              industry database is 25 years, with very few utilities employing something less than 20
 5              years. 117 Thus, Mr. Spanos' claim of reliance on service lives used by other utilities is
 6              contrary to his artificially short proposed amortization period.
 7
 8              Relying on the parameters, which form the basis of Mr. Spanos' judgmental approach,
 9              would require a conservative estimate of a 20-year amortization period, with a possibly
10              more appropriate level of 25 years. However, in order to remain conservative, I am
11              recommending the retention of the existing 20-year life.
12
13   Q.         WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
14   A.         My recommendation for a 20-year amortization period results m a reduction in
15              amortization expense of $187,514 based on plant as of December 31, 2008. In addition, a
16              remaining life rate should be set at 4.12%.
17
18   Account 397.1
19
20   Q.         WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 397.1 - GENERAL-
21              COMMUNICATION EQUIPMENT?
22   A.         The Company proposes a 10-year amortization. 118
23
24   Q.         WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
25   A.         The Company's basis for this account is identical as to that noted for Account 391.2.




          117
            Response to Rose City 1-17.
          m Exhibit JJS-1 page 53.

                                                                                                        68
     1   Q.         DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
     2   A.         No. In this case, the proposed amortization period is artificially short. Therefore, I
     3              recommend a 15-year amortization as a conservative value. A review of the Company's
     4              actual historical data identifies that the use of the 10-year amortization period will begin
     5              allowing the Company to more than fully accrue the investment in this account. 119 In fact,
     6              as of now, portions of the Company's original cost are over-amortized. Turning to Mr.
     7              Spanos' industry database, one would also find that my recommended 15-year
     8              amortization period is by far more prevalent than any other value reported. 120 Relatively
     9              few utilities in Mr. Spanos' database utilize amortization periods as low as 10 years. 121
    10              Another consideration for recommending a 15-year amortization period is the fact the
    11              existing combined Account 397 life expectancy is 19 years, as approved in Docket No.
    12              16705. Therefore, given the fact that Account 397.2 corresponds to microwave
    13              equipment, one might expect a shorter life span for the remaining investment reflected in
    14              Account 397.1, but not to a level of only 10 years as proposed by Mr. Spanos.
    15
    16   Q.         WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
    17   A.         My recommendation for a 15-year amortization period results in a reduction of $167,904
    18              based on plant as of December 31, 2008. The resulting amortization remaining life rate
    19              for the investment is 5.72%.
    20
    21   Account 397.2
    22
    23   Q.         WHAT DOES THE COMPANY PROPOSE FOR ACCOUNT 397.2-GENERAL
    24              COMMUNICATIONS EQUIPMENT-MICRO WAVE?
    25   A.         The Company proposes a 15-year amortization period. 122

~   26
    27   Q.         WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
    28   A.         The Company's basis is the same as previously stated for Account 391.2.


              119
                  Id., at page 309.
              120
                  Response to Rose City 1-17.
              121
                  Response to Rose City 1-17.
              122
                  Exhibit JJS-1page53.
I                                                                                                            69

I
 1   Q.          DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
 2   A.         No. Again, the Company's proposal is artificially short. Therefore, I recommend a 20-
 3               year amortization period for the investment in this account. First, it must be noted that the
 4               existing life expectancy for this account is 19 years, as set in Docket No. 16705. Given
 5               that this account is now segregated between microwave equipment and remaining
 6               communication equipment, and the fact that the remaining communication equipment has
 7               a lower overall life, the life expectancy for microwave equipment should be greater than
 8               the existing 19-year time frame. Therefore, this portion of Mr. Spanos' stated judgmental
 9               basis supports a longer amortization period than what he has proposed.
10
11               Turning to industry data, Mr. Spanos only identifies one utility with an equivalent sub-
12               account identification. 123 That utility is Chugach Electric Association, which reported a
13               15-year period. This is a generation cooperative in the Anchorage, Alaska area.
14               Amortization of microwave equipment subject to the weather conditions in Alaska can
15               reasonably be assumed harsher than reflected in the lower 48 states. Therefore, from a
16              judgmental basis associated with industry information, Mr. Spanos should have proposed
17               a longer amortization period.
18
19               Finally, the most important aspect of the need for a longer amortization period is the fact
20               that almost half of the investment in this account is already fully accrued using a 15-year
21               amortization period. 124 The Company has substantial levels of investment that was placed
22               in service back in 1983 through 1985. In addition, substantial levels of additional
23               investment are at the point where they will become fully accrued (a form of accelerated
24               depreciation) if the 15-year amortization period is adopted. Therefore, I recommend a
25               minimum 20-year amortization period. In addition, I recommend that the Commission
26               order the Company to correct its reserve associated with any account that is fully accrued
27               and recognize the additional depreciation or amortization that should have been booked.
28               The Company's failure to comply with normal regulatory requirements to continue to
29               apply approved depreciation rates to all gross plant in service is inappropriate. The


          123
                Response to Rose City 1-17.
          124
                Exhibit JJS-1 page 310.

                                                                                                           70
 1               Company cannot be allowed to unilaterally and arbitrarily decide to cease the booking of
 2               amortization or depreciation when it believes that an account is fully accrued.
 3
 4   Q.          WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
 5   A.          My recommendation for a 20-year amortization period results in a reduction in
 6               amortization expense of $1,136,473 based on plant as of December 31, 2008. In addition,
 7               my recommendation results in an amortization rate of 1.67%.

 8   6. Mass Property Net Salvage
 9
10   Q.          WHAT        ISSUE       DO    YOU      ADDRESS          IN    TIDS     PORTION   OF   YOUR
11               T ESTIMONY?
12   A.          I will address the Company's request for a significant increase in revenue requirements
13               associated with more negative net salvage for the Company's mass property plant
14               accounts. After review of the underlying information I recommend retention of the
15               existing net salvage levels.
16
17   Q.          WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSAL?
18   A.          The Company claims to have relied upon a 5-year historical database for its analyses. 125
19               Mr. Spanos claims he performed his analysis "based on common depreciation accounting
20               practices and judgment." 126 Mr. Spanos further stated that for many of the accounts, the
21               analyses of the 5 years of historical data did not produce conclusive results, therefore
22               judgment and industry averages were a major factor for those accounts. 127 Mr. Spanos
23               admits that for approximately 60% of the depreciable plant he based his proposal on
24               judgment and comparison with other utility information. 128




          125
                Exhibit JJS-1 pages 188-207 and Direct Testimony of Mr. Spanos at page 22.
          126
                Direct Testimony of Mr. Spanos at page 22.
          127   ld.
          128
                Exhibit JJS-1 page 37.

                                                                                                         71
 1   Q.         DID MR. SPANOS PROVIDE ANY DETAILED INFORMATION BY ACCOUNT
 2              INms TESTIMONY OR DEPRECIATION STUDY THAT WOULD IDENTIFY
 3              HOW HE SPECIFICALLy ARRIVED AT ms PROPOSED vALUES FOR EACH
 4              INDIVIDUAL MASS PROPERTY ACCOUNT?
 5   A.         No, other than a partial explanation for Account 365 used as an example in his 2008
 6              Study. 129 This is one of the accounts where Mr. Spanos claims he relied heavily on the
 7              statistical information derived from his 5-year database. Even for this account, Mr.
 8              Spanos admits that the cost of removal fluctuated quite a bit throughout the 5-year period
 9              and that such fluctuations "were a result of storms that forced higher labor costs for
10              removing assets." 130 (Emphasis added). Mr. Spanos then compared the 5-year average to
11              the range of what other electric companies estimated for this account. However, when his
12              comparison with the industry data pointed out that ETI's 5-year average of a negative
13              50% was not only outside the industry range but was also more than double the midpoint
14              of the range employed by other utilities, Mr. Spanos then concluded that the historical
15              statistical analysis was adequate, taking into account the "conditions of the region." 131
16              Thus, Mr. Spanos' single narrative example added confusion rather than clarity given that
17              he totally disregarded his own industry data even though for Account 352 he did the
18              opposite and ignored the Company's actual historical data and relied on industry data for
19              what he viewed as appropriate. 132 Thus, we are left with a very generalized stated criteria,
20              a less than explanative or supported example, and then inconsistent actions with no
21              explanation. This leaves a situation where the Company has presented nothing of
22              substance as the basis for its mass property net salvage proposals.
23
24   Q.         IS THE 5-YEAR DATABASE RELIED UPON BY MR. SPANOS ADEQUATE TO
25              ESTABLISH A REASONABLE INDICATION OF WHAT MIGHT OCCUR IN
26              THE FUTURE?
27   A.         No. First it must be emphasized that the 5-year period Mr. Spanos relied on is an
28              exceptionally short timeframe for performing a historical analysis for net salvage


          129
              Exhibit JJS-1 pages 37 and 38.
          130
              Id., at page 38.
          131 Id.
          132
              Depreciation of Mr. Spanos on April 20, 2010 at TR 125-126.

                                                                                                          72


                                                                                                                I
     1         purposes. Indeed, Mr. Spanos ·relied on a 16-year period for his identical analysis in the
     2         El Paso Electric case filed at the same time before this Commission. Moreover, reliance
     3         on only a 5-year database for this type of analysis is anything but a "common
     4         depreciation accounting practice" as claimed by Mr. Spanos. Next, Mr. Spanos
     5         recognizes that the limited historical database is skewed due to results of storms that
     6         forced higher labor costs. What Mr. Spanos glossed over is that these referenced storms
     7         are major hurricanes. Indeed, on September 24, 2005 Hurricane Rita hit the area with 120
     8         mile per hour winds. On September 13, 2007, Hurricane Humberto hit the area with 85
     9         mile per hour winds. Then on September 13, 2008 Hurricane Ike hit the Texas coast with
    10         110 mile per hour winds. 133 Thus, in the 5-year period relied upon for indications of the
    11         future, the area was hit with at least 3 hurricanes, two of which would be categorized as
    12         severe. This compares to only 7 hurricanes hitting the Texas coast at or east of Galveston
    13         during the past 38 years. 134 That represents only one hurricane every 5.4 years during the
    14         past 38 years compared to Mr. Spanos' database, which reflects such an occurrence once
    15         every 1. 7 years. This represents an extremely skewed database. Next, due to the fact that
    16         cost of removal and gross salvage may be recorded many years after a retirement is
    17         recorded, the lack of time synchronization further diminishes the value of a short 5-year
    18         database.
    19
    20         In addition, it turns out the database relied upon and presented by account does not reflect
    21         actual information by account. Only through repeated attempts during discovery was it
    22         determined that the account-specific 5-year data relied upon and presented by Mr. Spanos
    23         in his 2008 Study represented an unsubstantiated allocation of net salvage values from
    24         the functional level. 135 In other words, even in those instances where Mr. Spanos claims
    25         to have given some significance to his statistical analysis, the underlying data was not

I   26
    27
               maintained by account and thus, cannot be assumed to be representative of the accounts.
               The Company's database is so flawed not only from the standpoint of timeframe, or the
    28         inclusion of major hurricanes, but also in the maintenance of account-specific data.



         133
             http://www.hurricanecity.com/city/portarthur.htm
         134
             Texas Hurricane History, National Weather Service.
         135
             Response to Rose City 1-21.

                                                                                                        73
 1              Indeed, while Mr. Spanos claims his allocation is "a little more than a gut" feeling, it "is
 2              not logged" anywhere and only resides in his head. 136
 3
 4   Q.         ARE THERE ERRORS IN THE COMPANY'S PROCESS OF ASSIGNING
 5              FUNCTIONAL VALUES TO INDIVIDUAL PLANT ACCOUNTS?
 6   A.         Yes. Not only are there reversal of signs (i.e., reporting values as being negative when
 7              they should have been positive) in the data, but there are theoretically impossible values
 8              reflected in the data. 137
 9
10   Q.         TURNING TO THOSE INSTANCES WHERE MR. SPANOS DID NOT RELY TO
11              ANY EXTENT ON TIIE CLAIMED. IDSTORICAL STATISTICAL ANALYSIS,
12              DID HE PROVIDE ANY SPECIFIC DOCUMENTED SUBSTANTIATION FOR
13              EACH ACCOUNT?
14   A.         No. This is important given that 60% of the investment falls into this category.
15
16   Q.         DOES      MR.     SPANOS        CLAIM        THAT       HE   MAINTAINED      ALL    SUCH
17              INFORMATION SUPPORTING ms BASIS IN ms HEAD?
18   A.         Yes. 138 When Mr. Spanos was requested in discovery to produce the items that affected
19              his judgment in a manner that could be verified, he stated that his judgmental process
20              cannot be quantified and therefore provided nothing. Indeed, Mr. Spanos stated that
21              ''there's no log that basically defines what's in my head." 139
22
23   Q.         DOES MR. SPANOS PERFORM A NUMBER OF DEPRECIATION STUDIES
24              ANNUALLY?
25   A.         Yes. During Mr. Spanos' deposition, he claimed that he performs about 20 depreciation
26              studies per year for the past 24 years. 140 Given that most utilities have dozens of plant
27              accounts means that the amount of detailed information that Mr. Spanos claims to
28              maintain in his head would be quite improbable.

          136
              Deposition of Mr. Spanos on April 20, 2010 at TR 32-33.
          137
              Response to Rose City 1-21 Attachment.
          138
              Deposition of Mr. Spanos on April 20, 2010 at TR 57-58.
          139
              Id., at TR 57.
          140
              Id., at TR 58.

                                                                                                         74
 1
 2   Q.          WAS MR. SPANOS ABLE TO DEMONSTRATE AN IMPRESSIVE ABILITY TO
 3               RECALL SPECIFIC ITEMS OF INFORMATION DURING                           ms DEPOSITION
 4               AS IT RELATES TO SPECIFIC FACTORS IN THE ETI STUDY?
 5   A.          No, quite the contrary. On any specific item for which Mr. Spanos was requested to
 6               provide detailed explanations, he could not recall what specific information might have
 7               been given to him from Company personnel or other factors. 141 The only documented
 8               items of information that may have impacted Mr. Spanos' judgment is set forth in his
 9               limited site visit notes. 142
10
11   Q.          HAVE YOU REVIEWED THE SITE VISIT NOTES THAT MR. SPANOS
12               PROVIDED IN DISCOVERY THAT SHOWS THE TOTALITY OF                                       ms
13               DOCUMENTED JUDGMENT?
14   A.          Yes.
15
16   Q.          DID YOU FIND THAT THE SITE VISIT NOTES PRODUCED ADEQUATE
17               SUPPORT FOR THE COMPANY'S NET SALVAGE PROPOSALS?
18   A.          No. First, it must be noted that the site visit notes are rather cryptic, at best. Even when
19               the.re are items of information noted, there is no underlying support for any claim. As of
20               this time, the Company has still not provided any underlying support for any of the
21               claims referenced in Mr. Spanos' site visit notes. Moreover, there is generally no
22               connection identified as to how any item of information affected the decision making
23               process for each account. This connection apparently resides only in Mr. Spanos' head
24               and cannot be quantified except when Mr. Spanos actually developed his various
25               proposals.
26
27   Q.          PLEASE SUMMARIZE THE COMPANY'S PRESENTATION.
28   A.          There are many serious flaws with the Company's presentation for its mass property net
29               salvage proposals. The time frame is too short, the data has been manipulated, the data


          141
                Id., at TR 106-107 for example.
          142
                Response to Rose City 1-15.

                                                                                                          75
 1        includes numerous major hurricanes as though they would continue to occur on an
 2        equally frequent basis in the future as they did in the limited 5-year period, the allocated
 3        data includes errors, the industry data relied upon is ignored when it interferes with the
 4        desired results, or the industry data reflects ranges so wide as to make the industry data
 5        meaningless as a valid basis for selection of any given value. Finally, the Company has
 6        failed to provide specific support for individual account proposals, even when
 7        specifically requested to provide such information. Thus, the interveners and the
 8        Commission are left with proposals by account without any discemable basis. The
 9        presentation by the Company leaves the parties with a ''take it or leave it" approach to its
10        proposals.
11
12   Q.   WHAT DO YOU RECOMMEND?
13   A.   Given the Company's presentation and available data, I believe the only realistic option
14        left to the interveners and the Commission is to take up the Company's offer of"take it or
15        leave it." I recommend leaving the existing net salvage proposals in place as the best
16        alternative left at this point and time. I further recommend that the Commission order the
17        Company to develop and justify a net salvage database by account for an historical period
18        of 10 years for its next depreciation study. In addition, the Commission should order the
19        Company to actually present information substantiating its proposals on an account by
20        account basis, including underlying support and documentation and order that the
21        Company's books be maintained in that manner on a going forward basis.
22
23   Q.   WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
24   A.   The standalone impact of my recommendation results in a $10.6 million reduction to
25        annual depreciation expense based on plant in service as of December 31, 2008.

26   7. ELG vs. ALG Calculation Procedure
27
28   Q.   WHAT IS THE PURPOSE OF TIDS PORTION OF YOUR TESTIMONY?
29   A.   This portion of my testimony addresses the Company's decision to employ the
30        depreciation calculation procedure identified as the ELG procedure.


                                                                                                   76
     1   Q.   WHAT DO YOU RECOMMEND?
     2   A.   For various reasons, including the change in the underlying data, I recommend reliance
     3        on the industry standard ALG calculation procedure.
     4
     5   Q.   HAS    TIDS     COMMISSION          IDSTORICALLY           RELIED      ON     THE     ALG
     6        PROCEDURE?
     7   A.   Yes, with the exception of adopting ELG for a limited number of accounts in ETI' s last
     8        fully litigated case, Docket No. 16705. For example, in PUC Docket No. 14965 Finding
     9        of Fact 95 states that "CPL's depreciation rate should be set using the average life group
    10        ("ALG") procedure." This is the typical calculation procedure that I am aware of that has
    11        been employed by the Commission in all prior proceedings. Given the change in the
    12        underlying data for ETI, even the prior limited acceptance of ELG by the Commission in
    13        Docket No. 16705, which was based on superior data, is no longer valid.
    14
    15   Q.   DOES MR. SPANOS ATTEMPT TO IDENTIFY THE DIFFERENCE IN
    16        CALCULATION           PROCEDURES           BETWEEN         THE      ELG      AND      ALG
    17        PROCEDURE IN ms TESTIMONY?
    18   A.   Yes. Beginning on page 23 and continuing through 27 of Mr. Spanos' testimony, he
    19        provides information comparing ELG and ALG depreciation procedures. I do not agree
    20        with certain aspects of Mr. Spanos' presentation. These differences will be discussed later
    21        and in Appendix B.
    22
    23   Q.   CAN     YOU      BRIEFLY        STATE      WHY       THE     ELG      PROCEDURE          IS

I   24        INAPPROPRIATE FOR UTILITY RATEMAKING PURPOSES?
    25   A.   Yes. The ALG procedure calculates the remaining life on an average investment basis,
    26        knowing that the projection will not be accurate for each vintage of additions and every
    27        item of plant added within each vintage. Alternatively, the ELG procedure, which also
    28        relies on the same less than perfect data and the same assumptions to derive the ASL and
    29        dispersion curve, culminates with a calculation of the remaining life that assume that
    30        every future year level of retirement is known with absolute precision for as much as 100
    31        years into the future. Such a concept of absolute precision when forecasting is illogical on

                                                                                                       77
 1        its face in the real world of utility operation, and would only be more accurate than the
 2        ALG procedure under the infinitesimally small possibility that future events on an annual
 3        basis will actually follow a precisely defined pattern, each and every year for the next 50
 4        to 100 years. Simply put, the ALG procedure recognizes and reflects reality, while the
 5        ELG procedure clings to the presumption of unobtainable theoretical precision. I submit
 6        that the probability of that occurring is so remote as to be nonexistent.
 7
 8   Q.   SETTING ASIDE THE TECHNICAL DISCUSSION OF ELG VERSUS ALG FOR
 9        NOW, CAN YOU PROVIDE AN EXAMPLE OF THE IMPACT BETWEEN THE
10        TWO PROCEDURES?
11   A.   Yes. The remaining life for individual vintage can be compared between the ELG and the
12        ALG procedures when the same ASL and corresponding dispersion curve are employed.
13        For example, for Account 353 - Transmission Station Equipment, Mr. Spanos has
14        proposed a 45-R2.5 life-curve combination. Logically, one would normally assume that
15        brand new plant added into service at mid-year with an expected overall 45-year ASL
16        would have approximately a 44.5-year (45-0.5) remaining life at the end of the first year.
17        The precise value at the end of the first year for the 45-R2.5 life-curve combination is
18        44.53 years under an ALG procedure. However, review of the 2008 vintage addition for
19        ETI identifies a remaining life that is nowhere near the 45-year value for new plant in
20        service at the end of the first year. In fact, Mr. Spanos assigned the 2008 vintage addition
21        a 33.17-year remaining life due to his use of the ELG procedure. In other words, under
22        the ALG process, a 2008 vintage addition has a remaining life approximately 99%
23        (44.5/45) of the ASL when first placed into service, while the same 2008 vintage addition
24        has a remaining life of only 73.7% (33.17/45) of the ASL under the ELG procedure.
25        Approximately one-fourth of the remaining life for the newest vintages is eliminated
26        under the accelerated depreciation calculation of ELG, when compared to the ALG
27        procedure. It is this dramatic difference that is created by the acceleration caused by the
28        ELG calculation procedure that appeals to utilities that seek accelerated capital recovery.
29        Indeed, the overall ELG remaining life for Account 353 is 25.63 years, while the ALG
30        remaining life for the same data is 31.05 years, or 21 % higher. The artificially short ELG



                                                                                                   78
                  remaining life increases annual depreciation expense for this single account by
     2            approximately $1.8 million.
     3
     4   Q.       HAVE       YOU      TESTED        THE     RELATIONSHIP           BETWEEN         ACTUAL
     5            RETIREMENT ACTIVITY FOR TRANSMISSION ACCOUNT 353 DURING
     6            THE PAST 5 YEARS COMPARED TO WHAT WOULD BE ASSUMED
     7            THROUGH THE ELG PROCEDURE?
     8   A.       Yes. In order to demonstrate the false premise relied upon by Mr. Spanos regarding the
     9            theoretical precision of the ELG procedure; I tested the ELG proposed relationships
    10            against reality for the largest mass property account for the past 5 years. Transmission
    11            Account 353 is the largest mass property account and reflects over $370 million of
    12            investment as of December 31, 2008. Based on Mr. Spanos' assumed 45-R2.5 life-curve
    13            combination, and testing such proposal on an ELG basis for the most recent 5 years
    14            (2004-2008), one finds a dramatic difference between the assumed precision in the ELG
    15            procedure and actual events. The table below identifies the expected ELG retirement
    16            amounts by year for each vintage addition for the years 2004-2008. There are 15
    17            expected levels of retirement activity, beginning with 5 values for the 2004 additions,

I   18            then 4 values for the 2005 addition, down to only one value for the 2008 addition.


                         ELG EXPECTED RETIREMENTS BY VINTAGE ADDITION


          Year          Addition           2008           2007          2006           2005          2004
          2008        $10,225,616          $6,283
          2007         $7,404,974          $9,791        $4,550
          2006        $25 '744,244        $37,100       $34,040        $15,818
          2005        $20,005,825         $31,409       $28,831        $26,452        $12,292
          2004         $6,979,660         $12.021       $10.958        $10.058        $9.229        $4.289
          Total                           $96,604       $78,378        $52,329        $21,521       $4,289


    19            The following table reflects the actual retirement activity for the vintage additions for the
    20            years 2004-2008 and sets forth the errors between the actual retirement activity and what
    21            Mr. Spanos' ELG procedure would have assumed.



                                                                                                             79
 l                             ACTUAL RETIREMENTS BY VINTAGE BY YEAR


                      Year              2008             2007             2006       2005       2004
                2008                   $0.00
                2007                   $0.00            $0.00
                2006                  $187.08           $0.00              $0.00
                2005                 $15,447.35         $0.00              $0.00      $0.00
                2004                   $0.00          $12.014.15           $0.00      $0.00     $0.00
                Total                $15,634.43       $12,014.15           $0.00      $0.00     $0.00
                ELG Expected         $96,604.05       $78,378.39        $52,329.05 $21,521.10 $4,288.58
                ELG Error-$          $80,969.62       $66,364.24        $52,329.05 $21,521.10 $4,288.58
                ELG Error-%            83.8%            84.7%             100.0%     100.0%    100.0%

 2               As can be seen, there are only 3 retirement values out of the potential of 15 values that
 3               should have occurred had ELG been an accurate estimator. Moreover, one of the three
 4               values that did occur is only a $187.08 at a point in time where the ELG procedure would
 5               have expected $37,100 of retirement activity. A review of the data for the largest single
 6               account as set forth in the two tables above clearly demonstrates that there is no
 7               reasonable precision between the ELG calculation procedure and actual transactions. In
 8               fact, for the 5-year period analyzed, the ELG procedure predicted a total of $253,121 of
 9               retirements, while only $27,648 of actual retirements occurred, or only 11 % of the
10               expected total. This is precisely why the theory of ELG fails in any attempt to mirror the
11               real world of utility operations.
12
13   Q.          ABOVE AND BEYOND THE PRACTICAL FALLACIES OF THE ELG
14               PROCEDURE, ARE THERE SPECIFIC PROBLEMS WITH THE COMPANY'S
15               ELG CALCULATIONS?
16   A.          Yes. Mr. Spanos' calculation of ELG values is incorrect. Indeed, Mr. Spanos admits that
17               there appears to be an "anomaly" in his calculations. 143 There is no life-curve
18               combination that could be used in an ELG calculation procedure that would yield any
19               reasonable level of accuracy for the 5-year example above.




          143
                Deposition of Mr. Spanos on April 20, 2010 at TR 140.

                                                                                                          80
     1   Q.       WHAT WAS THE ANOMALY TO WlllCH MR. SPANOS REFERS?
     2   A.       On Exhibit JJS-1 at page 258, Mr. Spanos presents his ELG calculation for Account 352
     3            - Transmission Structures & Improvements. When asked why the remaining life for the
     4            2008 vintage addition of 36.67 years was shorter than the remaining lives for older
     5            vintage additions, Mr. Spanos admitted that that was "slightly unusual" and represented a
     6            "slight anomaly." 144 Indeed, having a shorter remaining life for the newer vintages is
     7            more than a slight anomaly - it is a theoretically impossible situation.
     8
     9   Q.       IS TIDS THE ONLY ANOMALY REFLECTED IN MR. SPANOS' STUDY?
    10   A.       No. Moreover, the claimed "slight" anomaly grows into a major anomaly in other
I   11            accounts, such as for Account 365. In Account 365 - Distribution Overhead Conductors
    12            and Devices, the remaining life for vintage addition 2008 is only 15.13 years, then
    13            increases to 18.38 years for the 2007 vintage additions. In fact, as set forth in the table
    14            below, the remaining life increases for each vintage addition from 2008 back through
    15            2001. The remaining life then decreases for the 2000 addition, but turns around once
    16            again and increases for the 1999 vintage addition. Not only do we have a major anomaly
    17            in that remaining lives are increasing for older plant addition, but Mr. Spanos' calculation


I   18
    19
                  yields a second theoretical impossibility by increasing - then decreasing - then again
                  increasing the remaining life as older vintages are analyzed. The remaining life
    20            calculation should be a continuous movement in one direction (lower remaining lives for
    21            older vintages) and would not, unless there were an error, increase or change directions
    22            multiple times.




              i44Id.

                                                                                                            81
                          ELG REMAINING LIVES FOR ACCOUNT 365


                         Vintage              Remaining
                          Year                  Life                  Difference
                          1998                   21.65                  (0.10)
                          1999                   21.75                   0.04
                          2000                   21.71                  (0.03)
                          2001                   21.74                   0.15
                          2002                   21.59                   0.21
                          2003                   21.38                   0.31
                          2004                   21.07                   0.53
                          2005                   20.54                   0.82
                          2006                   19.72                   1.34
                          2007                   18.38                   3.25
                          2008                   15.13


 2   Q.   CAN THE COMMISSION RELY ON MR. SPANOS' ELG PRESENTATION
3         EVEN IF IT HAD AN INCLINATION TO ACCEPT AN ELG CALCULATION?
4    A.   No. Even if the Commission had an inclination to accept the ELG procedure, it cannot do
 5        so because of the inaccurate calculations reflected in the Company's presentation. Simply
6         put, not only is the theory underlying the ELG procedure inappropriate in the real world
 7        of utility operations, but also the quantification of ELG results is faulty, thus rendering
 8        the Company's ELG presentation in this proceeding fatally flawed and lacking any
 9        credibility.
10
11   Q.   HAS MR. SPANOS ATTEMPTED TO REVOKE                         ms    USE OF THE WORD
12        ANOMALY IN REFERENCE TO ms CALCULATION PROCEDURE?
13   A.   Yes. In response to Rose City 24-38, Mr. Spanos attempts to claim that his use of the
14        word anomaly was not a reference to an error in his program. Mr. Spanos attempts to
15        divert attention from his theoretically impossible results by: (1) indicating that the
16        anomaly might be associated with the mid-year convention; (2) discussing the composite
17        remaining life calculation rather than the vintage remaining life values; and (3) claiming
18        the vintage remaining life is calculated by dividing the future accruals by the annual
19        accruals by vintage. In other words, he claims that the remaining life is not a function of
20        the ASL and dispersion pattern combination, but rather a calculation of dividing future

                                                                                                  82
 1        accrual values by annual accruals. Mr. Spanos concludes his response by claiming that
 2        the 2008 vintage remaining life being shorter than the 2007 vintage remaining life "is not
 3        truly an anomaly, but a refinement of the annualized rate."
 4
 5   Q.   IS THERE ANY VALIDITY TO MR. SPANOS' CLAIM REGARDING THE MID-
 6        YEAR CONVENTION AS A BASIS FOR ms ANOMALY-REFINEMENT?
 7   A.   No. As noted in the table above for Account 365 and as reflected in numerous accounts,
 8        the anomaly-refinement occurs for many vintages including the most current vintage to
 9        which Mr. Spanos claims the half-year convention has an additional impact. The half-
10        year impact for the most current vintage is already addressed when an ASL and
11        corresponding dispersion pattern are selected. Simply put, Mr. Spanos' reference to the
12        half-year convention is misleading and disingenuous.
13
14   Q.   DOES MR. SPANOS' DISCUSSION OF THE COMPOSITE REMAINING LIFE
15        CALCULATION SHED ANY LIGHT ON                          ms     CLAIMED ANOMALY-
16        REFINEMENT?
17   A.   No. Again, his reference to the composite remaining life is an attempted diversion from
18        the real issue, which is his claimed anomaly-refinement associated with individual
19        vintage remaining lives. It is theoretically impossible to have increasing remaining lives
20        for older vintages. The vintage remaining life calculation is the issue at hand, not the
21        composite remaining life. Mr. Spanos is well aware of the distinction and thus, his data
22        response represents yet another distortion.
23
24   Q.   IS THERE ANY BASIS IN MR. SPANOS' CLAIM THAT THE VINTAGE
25        REMAINING         LIFE    IS   CALCULATED          BY     DIVIDING      THE     FUTURE
26        ACCRUALS BY THE ANNUAL ACCRUALS BY VINTAGE?
27   A.   No. The vintage remaining lives are a function of the ASL and the corresponding
28        dispersion pattern. The vintage remaining lives are used to develop the annual accruals by
29        vintage. This process is accomplished by taking the future accruals (the total amount still
30        remaining to be recovered) and dividing it by the vintage remaining life, in order to
31        obtain the annual accruals by vintage, not the other way around as Mr. Spanos claims.

                                                                                                  83
 1              Even if Mr. Spanos did work backwards and developed the annual vintage accruals first,
 2              he would still need to rely implicitly on the vintage remaining lives derived from the
 3              proposed life-curve combination. All such life-curve combinations must yield declining
 4              remaining lives for older vintages unless there is an error.
 5
 6   Q.         CAN YOU FIND THE IDENTICAL ASL AND DISPERSION PATTERN FOR
 7              DIFFERENT ACCOUNTS IN MR. SPANOS' PRESENTATION?
 8   A.         Yes. For example, Accounts 369.1 and 369.2 - Distribution Overhead and Underground
 9              Services, respectively, have the same ASL and dispersion pattern. 145 The original cost,
10              calculated reserve, allocated book reserves and future accruals are different for every
11              single vintage between the two accounts. The one thing that is constant, since it is derived
12              from the same ASL and dispersion pattern, are the vintage remaining lives. In fact, they
13              are identical down to the hundredth of a decimal place as would be expected as they are
14              derived from the same ASL and dispersion pattern. IfMr. Spanos would have us believe
15              that the remaining life factors were not derived from the ASL and corresponding
16              dispersion pattern, but rather by taking the resulting annual accruals by vintage and
17              dividing those into the future book accruals by vintage and thus, deriving the remaining
18              life, then the potential of coincidence that they would produce the identical remaining life
19              values by vintage to one hundredth of a percent value would be astronomical. Thus, Mr.
20              Spanos' own depreciation study clearly refutes his claim.
21
22   Q.         IS THERE YET ANOTHER COMBINATION OF ACCOUNTS FOR WHICH
23              MR. SPANOS PROPOSES THE SAME ASL AND DISPERSION PATTERN?
24   A.         Yes. Mr. Spanos proposed the same 40-S0.5 for distribution Account 364 - Poles,
25              Towers and Fixtures, as well as Account 373.2 - Non-Roadway Lighting. 146 Due to the
26              unusual manner in which Mr. Spanos' procedure artificially limits the allocation of book
27              reserve to a maximum of the original cost less net salvage, Account 373.2 only reflects        I
28              one vintage remaining life, that being for the 2008 vintage. However, that vintage
29              remaining life for Account 372.2 is, again, identical to the corresponding 2008 vintage


          145
              Exhibit JJS-1page289-291.
                                                                                                               I
          146
              Exhibit JJS-1 pages 276-278 and page 298.

                                                                                                         84    I
                                                                                                               I
 1               for Account 364 down to the one hundredth of a decimal point level of accuracy. Again,
 2               the possibility of another coincidence of this situation is so remote as to defy credibility.
 3               Simply put, Mr. Spanos' attempt to divert attention from his anomaly, which is an error,
 4               and claim that it is a refinement of the annualized rate is disingenuous. The real answer is
 5               Mr. Spanos has a problem in his calculation procedure and refuses to admit to such
 6               problem by employing deception in his explanative response to request for information
 7               Rose City 24-38.
 8
 9   Q.          WAS       MR.      SPANOS      REQUESTED          TO     PROVIDE        A    NARRATIVE
IO               EXPLANATION ALONG WITH NUMERICAL EXAMPLE AND ALL ACTUAL
11               FORMULAS ASSOCIATED WITH HIS ELG COMPUTER PROGRAM THAT
12               DEMONSTRATES HOW THE ANOMALY COULD OCCUR FOR CERTAIN
13               ACCOUNTS?
14   A.          Yes. 147 However, Mr. Spanos failed to provide a single formula or numerical example
15               that supports the validity of his claimed refinement.
16
17   Q.          WHAT DO YOU RECOMMEND?
18   A.          I recommend the utilization of the standard industry practice of the ALG calculation
19               procedure. The ALG procedure is consistent with the overall process of depreciation,
20               which is based on analysis of numerous averages or broad brush approaches, recognizing
21               that historical indications and other information will only provide, at best, a reasonable
22               indication of what may transpire in the future on average. There will always be errors
23               between future projections and what actually transpires on an annual basis in the future;
24               however, the ALG procedure minimizes such error, while the ELG procedure maximizes
25               such error. Moreover, the ALG procedure is a standard straight-line approach, while the
26               ELG procedure represents an acceleration of capital recovery when compared to the
27               standard industry approach.




          147
                Response to Rose City 24-44.

                                                                                                           85
 1   Q.   IS THERE ADDITIONAL SUPPORT FOR WHY THE COMMISSION SHOULD
 2        NOT RELY ON THE FAULTY ELG PROCEDURE?
 3   A.   Yes. Given the extensive and technical nature of the problems to be addressed with the
 4        ELG procedure, I have attached Appendix B to my testimony, which addresses in further
 5        detail problems with the ELG procedure.
 6
 7   Q.   WHAT IS THE IMPACT OF YOUR RECOMMENDATION TO RELY
 8        EXCLUSIVELY ON THE ALG CALCULATION PROCEDURE?
 9   A.   The standalone impact of relying on the ALG calculation procedure for mass property
10        plant accounts results in a $19.3 million reduction in annual depreciation expense based
11        on plant as of December 31, 2008.

12   8. Remaining Life Method
13
14   Q.   WHAT DOES THIS PORTION OF YOUR TESTIMONY ADDRESS?
15   A.   This portion of my testimony addresses the Company's remaining life calculation.
16
17   Q.   WHAT DO YOU RECOMMEND?
18   A.   I recommend relying on the industry standard remaining life calculation.
19
20   Q.   DOES MR. SPANOS CLAIM THAT HE IS NOT PROPOSING A CHANGE
21        FROM THE REMAINING LIFE METHOD OF DEPRECIATION?
22   A.   Yes. Mr. Spanos states that on page 13 of his direct testimony. However, what he fails to
23        note is that the remaining life method he employs is different from the remaining life
24        previously used and employed by basically all other utilities and depreciation consultants
25        other than those utilities for which Gannett Fleming performs depreciation analyses. In
26        other words, using the identical data the remaining life calculation process previously
27        employed by the Company would produce a different remaining life in every instance
28        when compared to the new remaining life calculation process proposed by Gannett
29        Fleming.




                                                                                                 86
         Q.   WHAT IS THE DIFFERENCE BETWEEN THE STANDARD REMAINING LIFE
     2        CALCULATION AND THE NEW CALCULATION PROPOSED BY GANNETT
     3        FLEMING?
     4   A.   Gannett Fleming incorporates the impact of net salvage into the remaining life
     5        calculation. Thus, a change in the net salvage will result in a change to the composite
     6        remaining life for an account. This is illogical and inappropriate on its face.
     7
     8        Gannett Fleming's approach allocates the book reserve to individual vintage additions,
     9        but not on a consistent basis. Gannett Fleming further deviates from the standard
    10        approach by capping the level of accrued depreciation to the maximum level of the
    11        original cost plus the impact of net salvage. Thus, a plant account that has a 5-year ASL
    12        assigned to it, but has plant in service still at an age of 15 years would not reflect the
    13        over-depreciation that occurred during the additional 10 years of service. Gannett
    14        Fleming's approach artificially caps the level of reserve assigned to a vintage and spreads
    15        the balance to other vintages. Given that Gannett Fleming's approach relies on a dollar
    16        weighting of remaining life by vintage, that approach modifies the results of the standard
    17        remaining life calculation.
    18
    19   Q.   HAS TIDS ISSUE BEEN LITIGATED RECENTLY?
    20   A.   Yes. In a recent case in Florida in which the decision was rendered at the beginning of
    21        2010, the FPSC stated in its order for the FPL that:
    22
    23           For the reasons explained below, we are of the opinion that FPL's calculation
    24           of remaining life leads to questionable results. Accordingly, we approve of
    25           remaining life calculation based on using the average age of the given
    26           account, with the selected survivor curve. The remaining lives we approve
    27           below are based on this calculation.
    28                                               ***
    29           We do not agree with FPL that its remaining life calculation is consistent with
    30           FPL' s actual practice. FPL does not maintain its plant account reserves be
I   31
    32
                 vintage; they are maintained on a total account basis. Also, depreciation rates
                 are not applied to individual vintages; the rates are applied to the total account
    33           balance. Allocating the book reserve to individual vintages based on a
I   34
    35
                 theoretical reserve calculation is not necessarily a concern. However, in its
                 allocation, FPL determined that the reserve for any given vintage could not

I                                                                                                     87
 1                   exceed the survivors for that vintage less net salvage. For example, in
 2                   reviewing the calculation presented for Account 396. l, Power Operated
 3                   Equipment, no reserve was allocated to the 1986-2000 vintages because the
 4                   allocation of the reserve indicated that these vintages were fully accrued. That
 5                   is because the most allocated to any given vintage was the surviving
 6                   investment for that vintage less net salvage. These vintages represent more
 7                   than 36 percent of the plant account investment. We believe this is a
 8                   significant amount of investment that has no remaining life. Looking at
 9                   Account 396.8, Other Power Operated Equipment, FPL uses an L0.5 Iowa
10                   curve and 9-year life combination. The average age of the account is 7.5
11                   years. Using the method endorses by OPC, the remaining life of the account is
12                   5.2 years, compared to the Company's calculation of zero. While this account
13                   has an existing reserve surplus, that should not deter from the fact that it does
14                   indeed have a remaining life using FPL's proposed curve and life
15                   combination.
16
17                   FPL did not dispute that net salvage impacts its calculation of remaining life.
18                   Net salvage impacts the remaining life depreciation rate, not the average
19                   remaining life itself. 148 Unfortunately, because FPL's calculation assumes that
20                   no vintage can have more reserve allocated than the surviving investment less
21                   net salvage, as net salvage varies, so does the remaining life. For all the
22                   foregoing reasons. FPL' s remaining life calculation leads to questionable
23                   results. Accordingly, the remaining lives we address below are calculated by
24                   applying the average age of the account to the selected survivor curve. This is
25                   similar to OPC's calculation of remaining life and PEF's calculation in its
26                   depreciation study in Docket No. 090079-EI. The remaining lives we approve
27                   below use this calculation. 149
28
29               In other words, after a fully litigated analysis of the remaining life calculation, the FPSC
30               found that it could not rely on Gannett Fleming's remaining life calculation since it
31               produces questionable results and is affected by changes in net salvage.
32
33   Q.          WHAT DO YOU RECOMMEND?
34   A.          In each instance where I have recommended a change in the life or dispersion pattern for
35               a mass property account or where I have proposed an ALG calculation procedure, I have
36               employed the standard remaining life calculation that all other depreciation consultants
37               employ other than Gannett Fleming. My calculation is the same calculation that the
38               Company previously employed prior to retaining Gannett Fleming.


          148
                Remaining Life Rate= (100-Net Salvage-Reserve)/Average Remaining Life. Rule 25-6.0436(l)(e), F.A.C.
          149
                Order No. PSC-10-0153-FOF-EI in Docket Nos. 080677-EI, 090130-EI at pages 26 and 27.

                                                                                                                  88
     1
     2   Q.   WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
     3   A.   The impact of my recommendation is reflected in the standalone mass property life
     4        recommendations and the standalone ALG calculations. Finally, the correct calculation is
     5        reflected in the combined impact adjustments set forth in my testimony.


     6   SECTION III:         FULLY ACCRUED DEPRECIATION
     7
     8   Q.   WHAT DO YOU ADDRESS IN THIS PORTION OF YOUR TESTIMONY?
     9   A.   I address the Company's action to cease the booking of depreciation in instances where
    10        an account or sub-account is unilaterally assumed to be fully accrued.
    11
    12   Q.   WHO       HAS    THE      AUTHORITY         TO     CHANGE        DEPRECIATION           OR
    13        AMORTIZATION RATES?
    14   A.   The adoption of depreciation or amortization rates rests solely with the regulator, not with
    15        the Company. This regulatory principal is essential in order to protect customers from
    16        inappropriate action that a utility might take. For example, if a utility had the unilateral
    17        right to change its depreciation rates as desired, it would be in the best interest of the
    18        utility's shareholders to immediately reduce or cease the booking of depreciation expense
    19        after the end of a rate case. If such practice were allowed, the utility would still recover
    20        the depreciation related revenue requirement level built in base rates, but customers
    21        would not receive the benefit expected with the payment of depreciation expense over
    22        time. The benefit customers receive for depreciation expenses is an offset to rate base for

I   23        the utility's recovery of its invested capital. The benefit of depreciation expense is
    24        booked into Account 108, the accumulated provision for depreciation ("APFD"). The

I   25        APFD is subtracted from gross plant in order to determine net plant. Net plant is the
    26        largest component of rate base.




I
                                                                                                       89

I
 1   Q.          HOW IS THE DEPRECIATION PROCESS PROPERLY PERFORMED BY A
 2               UTILITY?
 3   A.          Once a depreciation rate is adopted by a regulator, that rate should be applied to gross
 4               plant in service on a monthly basis until the plant retires.
 5
 6   Q.          DOES THE COMPANY FOLLOW TIDS FORMAT?
 7   A.          No. The Company's policy is that once it makes a unilateral decision that it believes an
 8               account has become fully accrued, it ceases the booking of depreciation expense to the
 9               APFD. 150 Thus, by not continuing the booking of depreciation expense, ETI has changed
10               the applicable depreciation rate to zero (0) rather than whatever rate the Commission
11               previously adopted. The unilateral decision to cease the booking of depreciation expense
12               is made even though the plant has not retired.
13
14   Q.          WHAT IS ETl'S STANDARD FOR ASSUMING A PLANT HAS BECOME
15               FULLY ACCRUED?
16   A.          When the Company "believes" it has recovered the total investment plus the impact of its
17               estimate of net salvage, it ceases the booking of depreciation expense. Thus, the standard
18               employed by ETI is its unilateral "belief."
19
20   Q.          WHAT IS THE IMPACT OF TIDS INAPPROPRIATE UNILATERAL ACTION?
21   A.          By ceasing the booking of depreciation expense, the Company understates the APFD and
22               thus on a going forward basis overstates rate base since the APFD is artificially not
23               permitted to increase. Moreover, this inappropriate practice deprives customers of the
24               return of their overpayment of depreciation expense through the remaining life
25               depreciation technique.
26
27   Q.          WHAT IS THE REMAINING LIFE DEPRECIATION TECHNIQUE?
28   A.          As set forth under the General section of my testimony on depreciation, the remaining
29               life technique attempts to recover the net depreciable investment less net salvage over the
30               remaining expected life of the account. The remaining net depreciable investment less net

          150
                Response to Rose City 1-19.

                                                                                                         90
     I              salvage can be either positive or negative. This approach recognizes that while recovery
     2              of net depreciable investment less net salvage may be under or over recovered, the intent
     3              is to allow only I 00% recovery, not more or less.
     4
     5   Q.         WHAT DID TmS COMMISSION ORDER REGARDING THE APPLICATION
     6              OF DEPRECIATION FOR Tms COMPANY?
     7   A.         In Docket No. 16705, the Company's last litigated rate case, the Commission ordered the
     8              adoption of "Staff's proposed depreciation rates."m (Emphasis added).
     9
    10   Q.         DOES THE COMPANY ADMIT THAT IT CEASED USING THE COMMISSION
    11              APPROVED RATES FROM DOCKET NO. 16705?
    12   A.         Yes. The Company admits that it "stopped booking depreciation" for 3 accounts. 152
    13
    14   Q.         WHO AT THE COMPANY MAKES THE DECISION AS TO WHEN AN
    15              ACCOUNTBECOMESFULLYACCRUED?
    16   A.         The Company stated that its software program, PowerPlant, has a built-in algorithm that
    17              automatically stops depreciation when a particular depreciation group is fully
    18              depreciated. 153 The Company implemented this specialized software in January 2004. 154
    19              It appears that prior to the implementation of this software progress this situation did not
    20              exist.
    21
    22   Q.         HOW DOES THE COMPANY JUSTIFY ITS ACTIONS?
    23   A.         The Company claims that depreciation is the loss of service value, as set forth in the

~   24              USOA. 155 The Company believes that the definition of service value limits depreciation
    25              to the original cost less net salvage. 156




I             151
                  Docket No. 16705 FOF 190.
              152
                  Response to Rose City 13-32c.
              153
                  Response to Rose City 13-32b.
              1s4 Id.
              155
                  Id., at (a).
              1s6 Id.


                                                                                                             91

I
 1   Q.          IS THE COMPANY CORRECT IN ITS BASIS?
 2   A.          No. As part of the same series of definitions relied upon by the Company in the USOA,
 3               there are general instructions which identify under depreciation accounting the reference
 4               to a rate. The USOA states that utilities "must use percentage rates of depreciation that
 5               are based on a method of depreciation that allocates in a systematic and rational
 6               manner." 157 The Company takes a unique interpretation of these series of items, which
 7               then allows it the unilateral authority to change a depreciation rate that has been approved
 8               by the Commission through the back door mechanism of an algorithm built into a
 9               software program that has never been approved by the Commission. This unique
10               interpretation of the USOA and hidden algorithms within software programs violate the
11               Commission's orders adopting depreciation rates in prior proceedings.
12
13   Q.          WOULD THE COMPANY'S ACTIONS BE APPROPRIATE IF IT WERE AN
14               UNREGULATED COMPANY?
15   A.          Yes. However, since ETI is a regulated utility, its actions are inappropriate because
16               captive customers would be forced to pay depreciation expense through rates approved
17               by the Commission without getting the benefit of the depreciation being added to the
18               accumulated reserve. Therefore, the Company's proposal must be rejected.
19
20   Q.          WHAT DO YOU RECOMMEND?
21   A.          I recommend that the Commission recognize the amount of loss in back depreciation
22               expense that should have been booked to the accumulated provision for depreciation
23               associated with three accounts referenced by the Company. As set forth on Schedule (JP-
24               2), the amount of additional depreciation expense that should have been recognized on
25               the Company's books and records through the end of the test-year in this case is
26               $6,160,578. I further recommend that the Commission order the Company to correct the
27               algorithm in its software system so as to comply with the booking of Commission
28               approved depreciation ate.




          is1   Id.

                                                                                                          92
 l   Q.   HOW SHOULD THE COMMISSION TREAT THIS AMOUNT?
 2   A.   The Commission should reduce rate base by the $6,160,578 amount noted above and
 3        amortize such amounts back to customers over a 4-year period. This would result in an
 4        additional $1,540,145 reduction in annual revenue requirements.


 5   SECTION IV:          SGSF CAPITAL RECOVERY
 6
 7   Q.   WHAT IS THE ISSUE IN THIS PORTION OF YOUR TESTIMONY?
 8   A.   In this portion of my testimony I discuss the Company's acquisition of the Spindletop
 9        Gas Storage Facility ("SGSF") and two key resulting issues. The first issue is the
10        recognition of the substantial positive net salvage identified by ETI. The second issue is
11        the correction of the excess recovery of investment on an accelerated basis.
12
13   Q.   WHAT DO YOU RECOMMEND?
14   A.   Given the unusual facts and circumstances surrounding the construction, financing,
15        capital payments, rate treatment, admission by the Company that these are customer
16        savings rather than shareholder profits, and the exercise of the purchase option,         I
17        recommend that: (1) current customers be reimbursed for their equitable right to the
18        current net depreciable value, and (2) current customers receive a credit for the $40
19        million of return of capital (i.e., depreciation) they have paid during the 1990s and early
20        2000s due to the special rate treatment granted the Company and that such credit be
21        amortized to current customers over a four-year period. Given that Cities' witness Mr.
22        Nalepa recommends the removal of all SGSF costs, the second above noted
23        recommendation is necessary in the event the Commission elects not to adopt Mr.
24        Nalepa's recommendation. In any event, the need to recognize the net salvage or sale
25        value is still required.


26   Q.   PLEASE       PROVIDE       THE     BACKGROUND           ASSOCIATED         WITH      THIS
27        PARTICULAR ISSUE.
28   A.   In the late 1980s and early 1990s, the Company's predecessor GSU was in a difficult
29        financial position. An opportunity arose where GSU could obtain a gas storage facility

                                                                                                  93
 1              for the benefit of customers. Unfortunately, due to its financial constraints, GSU could
 2              not purchase and construct the gas storage facility. It contracted with Sabine Gas
 3              Transportation Company ("SGT") to construct the facility and utilize it at the direction of
 4              GSU. GSU retained control of construction, modifications, and operation of the facility.
 5              In addition, the operating agreement included an option to purchase the facility from SGT
 6              at a "Payoff Amount". The "Payoff Amount" reflected a reduced net cost in association
 7              with the level of "Credit Payments" made by the Company. 158 The "Credit Payments"
 8              were costs the Commission allowed the Company to pass on to customers. In 2004, the
 9              Company exercised its purchase option and became the owner of the gas storage facility
10              for a $1.00 payment.
11
12   Q.         HAVE SGSF CAPITAL COSTS BEEN INCLUDED IN ELIGIBLE FUEL SINCE
13              ITS INCEPTION?

14   A.         Yes. In Docket No. l 0894, the Commission found that the "Credit Payments" to SGT for
15              capital reduction were costs that were passed on to customers. 159
16
17   Q.         WHAT IS THE VALUE OF THE FACILITY?
18   A.         Recently, the Company has appraised the value of the gas storage facility at $100
19              million. 160   In other words, the current best estimate of the value of SGSF is
20              $100,000,000 less the $1 it paid for the facility.
21
22   Q.         ARE THERE OTHER EVENTS CURRENTLY TRANSPIRING THAT IMPACT
23              THIS PARTICULAR ISSUE?
24   A.         Yes. As part the electric deregulation process in Texas, a jurisdictional separation has
25              been completed. The Company is now a distinct corporate entity, separate from Entergy
26              Gulf States Louisiana. While the ownership of SGSF remains with ETI, the completion
27              of the separation process may result in the sale of the Texas system. In fact, Entergy
28              Corporation chairman and Chief Executive Officer J. Wayne Leonard told shareholders
29              in November 2007 that he might sell the Texas operations if the jurisdictional split were

          158
              PUCT Docket No. 10894, Examiners' Report pages 106-110.
          159
              PUCT Docket No. 10894 Finding of Fact 288.
          160
              October 18, 2004 Hadco International Appraisal & Consulting Services.

                                                                                                        94
 1              approved by the Louisiana Public Service Commission. If this were to occur, or if
 2              deregulation is eventually implemented for the Company, Texas retail customers stand to
 3              lose the value of the facility they have already paid for and were previously promised.
 4              Thus, Texas retail customers may lose their share of the current $100 million gross
 5              salvage attributable to the SGSF unless action is taken.
 6
 7   Q.         WHY IS IT APPROPRIATE TO TAKE ACTION IN TIDS PROCEEDING?
 8   A.         In Docket No. 10894, this Commission specifically afforded the Company recovery for
 9              the capital costs of constructing the gas storage facility even though it did not own the
I0              facility. 161 This action was taken in spite of the Company's admission that if it had
11              constructed the facility itself it would have been subject to base rate treatment. 162 The
12              Company could not build the facility itself due to budgetary constraints at the time the
13              project to construct the gas storage facility became available. The Commission granted
14              the Company special treatment based in part on the fact that customers were expected to
15              benefit from the facility. The Commission also allowed the pass through of capital costs
16              (i.e., depreciation) on an accelerated basis. The Commission allowed the financing of the
17              facility to be paid within a 10-year period rather than the then-estimated 30-year useful
18              life of the facility. 163 Now, in recognition of the changed circumstances, and the drastic
19              intergenerational inequity that occurred for customers, it is only fair and equitable to level
20              the field for current and future customers due to prior significant overpayment.

21
22   Q.         WHAT DO YOU RECOMMEND?
23   A.         I recommend that with the changed circumstances associated with the purchase of the
24              facility for $1.00 by the Company that: (1) Texas retail customers be credited for their
25              allocable portion of the current $100 million valuation or net salvage, and (2) Texas retail
26              customers be given credit in the APFD for prior payments for the return of capital (i.e.,
27              depreciation). These recommendations are conservative in favor of the Company, given
28              that the gas storage facility may very well continue to increase in value.



          161
              PUC Docket 10894.
          162
              Id., at Finding of Fact 308.
          163
              Id., at Finding of Fact 310.

                                                                                                           95
 1   Q.   WHY DO YOU BELIEVE THAT THE VALUE OF THE FACILITIES WILL
 2        INCREASE IN THE FUTURE?
 3   A.   First and foremost, the value of the facilities increased by a factor of 2.5 times its original
 4        $40 million cost in a little over a decade ($100 million + $40 million = 2.5). This increase
 5        in value has occurred in large part due to the change in the natural gas industry and the
 6        resulting prices that suppliers have and can demand for their product. The price of gas has
 7        reached all-time highs in the last several years and the fact that the gas market is unstable,
 8        coupled with the concern for air quality associated with coal-fired generation and
 9        consideration of a return to a more robust economic market, results in the conclusion that
10        the future for gas prices will continue to be volatile and most likely be at a higher level
11        than experienced during the 1990s and early 2000s. As gas prices increase in cost over
12        time, the value of the gas storage facility further increases. Thus, in another 5 or 10 years
13        the gas storage facility may actually be valued at something much higher than the recent
14        estimate of $100 million to another entity. In the event the Commission opts to retain the
15        SGSF regulated service, the value should be revisited in future rate cases like other net
16        salvage values are expected to be revisited.
17
18   Q.   FROM AN EQIDTY STANDPOINT, ARE TEXAS RETAIL CUSTOMERS
19        ENTITLED TO THE VALUE OF TIDS FACILITY?
20   A.   Yes. There can be no doubt that Texas retail customers have paid their proportionate
21        share of basically all costs associated with this facility. Had GSU not been in a budgetary
22        constraint position when the opportunity arose to acquire the rights to build the gas
23        storage facility customers would have paid significantly lower fuel costs and base rate
24        charges. Historical fuel costs would have been lower since there would have been no
25        "Credit Payments" made to SGT. Moreover, base rates would not have increased on a
26        comparable basis if the original costs had been included in rate base. This result would
27        have occurred since the effective depreciation component of revenue requirements would
28        have essentially been minimal or even a negative value given the estimated gross salvage
29        for the value of the facility would have been subtracted from the original cost. This is
30        standard industry practice since the useful life of the facility would extend beyond the
31        estimated life of the generating facilities that it serves (Sabine and Lewis Creek


                                                                                                      96
                     generating stations). The last unit at the Sabine station is scheduled to retire no sooner
     2               than 2029 . 164 Thus, the gas storage facility could be sold at a substantial value above cost.
     3
     4               In addition, in compliance with the benefits-follows-burdens concept adopted by the
     5               Texas Supreme Court, the fact that customers have in fact paid for capital costs, operating
     6               costs, property taxes, and basically every other cost associated with the facility, entitles
     7               any gain on sale to be assignable to customers. 165
     8
     9   Q.          WHAT IS YOUR UNDERSTANDING OF THE DIRECTION THE COURTS
    10               HAVE PROVIDED TO THE COMMISSION REGARDING WHO IS ENTITLED
    11               TO THE GAIN INVALUE OF THE SGSF?
    12   A.          I have been advised by counsel that the Texas Supreme Court recognized that ''the proper
    13               allocation is a complicated one that cannot be resolved simply by reference to who paid
    14               for the property." 166 The court relied in part on the benefits-follows-burdens principal
    15               established in the Democratic Central Committee case. 167
    16
    17               The Court, while not requiring the Commission to consider all of the standards set forth
    18               in its ruling, nor forbidding it from considering others, listed a number of factors. The
    19               Court noted:
    20
    21                         In the general case, the gain should be allocated to that group (as
    22                         between shareholders and ratepayers) that has borne the financial
    23                         burdens (e.g., depreciation, maintenance, taxes) and risks of the asset
    24                         sold. In addition to these two general equitable factors, courts have
    25                         also considered numerous other factors, including whether the asset
    26                         sold had been included in the rate base over the years, whether the
    27                         asset was depreciable property, non depreciable property, or a
    28                         combination of the two types, the impact of the proposed allocation on
    29                         the financial strength of the utility, the reason for the asset's
    30                         appreciation (e.g., inflation, a general increase in property values in
    31                         the area), any advantages enjoyed by the shareholders because of
    32                         favored treatment accorded the asset, the dividends paid out to the


              164
                    Response to Rose City 1-16.
              165
                    798   s. w. 2d 560.
              166   ld.
                    Id.
I
              t67


                                                                                                                  97

I
 l               shareholders over the years, and any extraordinary burdens borne by
 2               the ratepayers in connection with that asset.
 3
 4   Q.   DID YOU CONSIDER VARIOUS FACTORS?
 5   A.   I have considered numerous factors. First while ETI did not own the plant prior to
 6        January 2005 and thus it was obviously not included in rate base, the treatment afforded
 7        the Company by the Commission was in fact superior to rate base treatment.               As
 8        previously noted, the Commission granted the Company the right to recognize all
 9        construction costs and operating costs as reconcilable fuel. By doing so, it allowed the
10        Company to pass basically all financial burdens on to customers and without the normal
11        regulatory lag and guaranteed cost recovery. In addition, the costs incurred by SGT for
12        property taxes, operation and maintenance expenses, etc. were also passed on to the
13        Company. The Company in tum included such costs as reconcilable fuel costs, which
14        were then passed on to customers. Once again, customers paid all operating and tax
15        impacts of the facility.
16
17   Q.   WERE CUSTOMERS RESPONSIBL E FOR DEPRECIATION?
18   A.   In effect, yes. While the amounts paid to SGT did not specifically identify depreciation, it
19        is an undeniable fact that the "Credit Payments" were for debt service requirements. The
20        principal and interest components of debt service requirements are the equivalent of
21        depreciation and return., respectively for plant afforded base rate treatment. Thus, the
22        principal payment is the equivalent of depreciation, and the interest portion of the debt
23        service payment is the equivalent of return.. Therefore, while not identified specifically as
24        depreciation, customers did pay the equivalent of depreciation for the investment. This
25        fact also demonstrates that the regulatory treatment afforded the Company was more than
26        the equivalent of providing rate base treatment over the entire operating life of the
27        facility. This represents yet another burden carried by customers, not the Company.




                                                                                                    98
     1
     2   Q.   DOES     YOUR      RECOMMENDED            100%     ALLOCATION          OF    GAIN     TO
     3        CUSTOMERS TAKE INTO ACCOUNT THE FINANCIAL STRENGTH OF THE
     4        COMPANY?
     5   A.   Yes. While GSU was not in a financial position to construct the facility back in the early
     6        1990s, that situation was rectified when GSU merged with Entergy. In fact one of the
     7        benefits touted by Entergy in association with its proposed merger at that time was the
     8        financial strength that it brought to the GSU system. Moreover, the financial strength of
     9        the utility has been enhanced by normal regulatory treatment in rate proceedings as well
    10        as very unique and special legislative treatments realized by the Company over the last
    11        several years as it pertains to recovery of capacity charges and hurricane damage costs
    12        during the period when the Company had been in a base rate freeze. In addition, when
    13        the Company was granted fuel reconciliation treatment for the cost associated with the
    14        SGSF it was granted favorable rate treatment for this particular asset. Had the Company
    15        been required to place the asset into base rates rather than receiving reconcilable fuel
    16        treatment it would have experienced a regulatory lag in recovery of funds and would not
    17        have been guaranteed recovery. This regulatory lag was eliminated by the Commission
    18        for the Company's use of the SGSF.
    19
    20   Q.   IS THE COMPANY RESPONSIBLE FOR THE INCREASE IN VALUE OF THE
    21        FACILITY OVER THE YEARS?
    22   A.   No. The value of the asset has increased due to market forces, not anything implemented
    23        by the Company.
    24
    25   Q.   IN SUMMARY, IS THERE ANY FACTOR THAT YOU'VE IDENTIFIED
    26        WHICH WOULD INDICATE THAT THE COMPANY'S SHAREHOLDERS
I   27        WERE ENTITLED TO SOME PORTION OF THE GAIN TO BE OBTAINED
              FROM THE ULTIMATE DISPOSITION OF TffiS FACILITY?
I   28
    29   A.   No. Based on every meaningful factor I have been able to identify associated with the


I   30
    31
              construction, financing, operations, etc. of this facility, it has been customers who are
              responsible for each component. As such, in my opinion it would clearly be in violation

I                                                                                                     99

I
 1               of the principals set forth by the Supreme Court of Texas if the Company were to be
 2               afforded any portion of the gain in value of this facility. Moreover, in Docket No. 10894,
 3               Company witness Mr. Harrington stated that the savings of the project were for
 4               customers, not shareholders. 168
 5
 6   Q.          HOW DO YOU PROPOSE TO RECOGNIZE THE $100 MILLION VALUE FOR
 7               TEXAS RETAIL CUSTOMERS?
 8   A.          As of January 2005, the Company took ownership of the facility after purchasing the
 9               facility for $1.00. Texas retail customers should be credited with their allocable portion
10               of the $100 million value as of that point in time. As shown on Schedule (JP-3) this
11               results in a $42.5 million credit to the Texas retail jurisdiction. I recommend that the
12               amount be returned to customers over the 35.5-year remaining life I recommended for
13               Sabine 5, or $1,197,183 annually. This amount should be credited whether Mr. Nalepa's
14               recommendation is adopted.
15
16   Q.          WHY IS IT APPROPRIATE TO CREDIT CUSTOMERS FOR THE SGSF NET
17               SALVAGE         VALUE        WHETHER THE                PUC        ADOPTS   MR.   NALEPA'S
18               RECOMMENDATION?
19   A.          Mr. Nalepa's recommendation reflects a prudent business decision regarding the annual
20               benefits versus costs for the SGSF. My recommendation relates to the value that a
21               different owner with a different operating philosophy might have regarding the facility. It
22               is my understanding that Mr. Nalepa's recommendation is based on the changed
23               circumstances relating to reliability issues and annual costs of operation. ETI no longer
24               needs the facility, but that fact does not change the value of the facility to a new owner.
25               By analogy, this is no different than a family no longer needing a two-seat sports car once
26               they have children. The fact that a two-seat sports can no longer fit one family's situation
27               does not diminish the value of the car.




          168
                Mr. Harrington's rebuttal testimony at WEH-7 in Docket No. 10894.

                                                                                                         100
     1   Q.         TURNING           TO         YOUR           SECOND             ISSUE          RELATING              TO
     2              INTERGENERATIONAL INEQUITY, WHAT DO YOU RECOMMEND?
     3   A.         I recommend correcting the significant level of intergenerational inequity that currently
     4              exists by amortizing the future service value over a four-year period in conjunction with
     5              corresponding depreciation treatment of the estimated remaining life of the facility. This
     6              treatment will eliminate the "free ride" future customers will enjoy given the full, but
     7              accelerated, depreciation realized for the initial capital costs.
     8
     9   Q.         WHY      ARE      CUSTOMERS             ENTITLED          TO     A     CREDIT        FOR PRIOR
    10              ACCELERATED RETURN OF CAPITAL OR DEPRECIATION PAYMENTS?
    11   A.         Had the SGSF been afforded normal base rate treatment rather than the superior fuel
    12              treatment, the Company's books would already reflect the "Credit Payments" in the
    13              APFD (Account 108) as a credit to rate base. Given that customers were required to pay
    14              off the facility on an accelerated basis to meet the construction related finance
    15              requirements, it is only equitable to recognize such accelerated payments now that the
    16              Company has taken formal ownership of the facility. The Texas retail jurisdiction should
    17              be allocated its proportional share of the prior accelerated depreciation payments. This
    18              results in a $17 million adjustment to rate base. 169 In conjunction with this credit to rate
    19              base, I also recommend a four-year amortization in order to correct the substantial level
    20              of intergenerational inequity. This will result in a net $3.8 million annual credit. 170


    21   Q.         HAVE       OTHER        REGULATORS               ADOPTED           THE       CORRECTION             OF
    22              INTERGENERATIONAL INEQUITY AS YOU ARE RECOMMENDING IN

I   23
    24   A.
                    TIDSCASE?
                    Yes. The FPSC within the past year ordered precisely this treatment I recommend in this

I   25              case. In fact, the FPSC ordered that state's two largest electric utilities to credit their



I
I             169


              170
                  Production demand allocation factor of 42.5% as noted in response to Rose City 2-6(c) times the $40 million
                   initial cost.
                  $17 million amortized over 4 years equals $$4,250,000, less $17 million depreciated over 35 years equals

I                  $485,714.

                                                                                                                        101
 1              retail customers with approximately $1 billion of excess or prior accelerated depreciation
 2              over a four-year period. 171
 3
 4   Q.         WHAT ANNUAL LEVEL OF DEPRECIATION WILL CUSTOMERS BE
 5              REQUIRED TO INCUR ASSOCIATED WITH YOUR RECOMMENDATION?
 6   A.         As part of my recommendation customers will be required to pay $485,714 of annual
 7              depreciation expense in order to extinguish the $17 million rate base credit over the 35-
 8              year remaining life I am recommending.
 9
IO   Q.         WILL FUTURE CUSTOMERS HAVE TO PAY FOR A PORTION OF YOUR
11              RECOMMENDATIONS?
12   A.         Yes. After the proposed 4-year amortization is over and the Company files for a change
13              in base rates, future customers will begin paying a return and depreciation on the
14              $17million portion of my recommendation for the remaining life of the facility. This
15              future payment will better meet the regulatory matching principle tying the payment by
16              those customers to the benefit of the storage facility being used to provide that generation
17              of customer's electric service. The will be no need for future customers to pay for the
18              $42.5 million portion of my recommendation given that value will be provided through
19              the sale of the facility after it is retired from utility service.


20   SECTION V:                 STORM INSURANCE RESERVE

21   1.         General
22
23   Q.         WHAT IS THE ISSUE IN TIDS PORTION OF YOUR TESTIMONY?
24   A.         The Company requests an insurance reserve storm cost accrual of $9,450,000. 172 This
25              request is comprised of two components. The first component of $4,180,000 relates to
26              recovering the Company's claimed $64.4 million deficit in its insurance reserve, plus
27              building the storm reserve to a positive $19 .3 million target. 173 The Company proposes to

          171
              FPSC Docket Nos. 080677-EI and 090079-EI, a FP&L and Progress Energy Florida case, respectively.
          172
              Direct testimony of Mr. Wilson at page 4.
          173
              Id.

                                                                                                                 102
     1          amortize this claimed $83.7 million ($64.4 million + $19.3 million) change in reserve
     2          position over a 20-year period, for a $4.18 million annual expense. The second
     3          component of the Company's proposed annual accrual is $5,270,000, which represents
     4          the Company's estimated annual ongoing storm losses. 174 In addition to these two
     5          components, ETI also requests $25,278,210 in rate base, to be amortized over 5 years at
     6          an annual rate of $5,055,642, associated with a proforma adjustment for hurricane
     7          securitization cost that were removed from the storm reserve. 175 This portion of my
     8          testimony addresses my recommendations to eliminate significant portions of the claimed
     9          historical reserve deficit, reduce the projected reserve target level, reduce the annual
    10          estimated storm loss expense, and assign storm reserve treatment to the proposed
    11          hurricane securitization proforma adjustment. As summarized in the table below, the
    12          combined impact of my recommendations reduces the Company's requested $9.45
    13          million annual revenue requirement by $7,703,810 and also reduces rate base by
    14          $45,867,967. I also recommend increasing the storm threshold level from $50,000 per
    15          storm to $500,000 per storm.


                                                   Rate Base Impact

I          Reserve Deficiency
                                                       ETI
                                                     $64,355,152
                                                                           Cities
                                                                          $47,497,395
                                                                                         Adjustment
                                                                                         ($16,857,757)
           Reserve Target                            $19,304,000          $15,572,000     ($3,732,000)
           Subtotal                                  $83,659,152          $63,069,395    ($20,589, 757)
           Hurricane Proforma                        $25,278,210                    ~    ($25,278,210)
           Total Rate Base                          $108,937,362          $63,069,395    ($45,867,967)
                                                Annual Accrual Imnact
           Rate Base Amortization                      $4,182,958           $3,153,470    ($1,029,488)
           Annual Loss Accrual                         $5,270,000           $3,651,320    ($1,618,680)
           Hurricane Proforma                          $5,055,642                   ~     ($5,055,642)

I          Total Annual Expense                      $14,508,600            $6,804,790    ($7,703,810)


I        174
               Id., at page 5.
         175
               Testimony of Mr. Wright at pages 19-20 and ETI Adjustment AJIS.10.

                                                                                                          103
 1   Q.         DOES THE COMMISSION PERMIT SELF-INSURANCE BY UTILITIES?
 2   A.         Yes. The Commission has implemented Substantive Rule 25.23l(b)(l)(G) relating to a
 3              self-insurance plan for storm damages. The establishment and operation of the insurance
 4              reserve is intended to produce a less costly approach to dealing with storm damage,
 5              which could not have been reasonably anticipated, than would be the case if the
 6              Company purchased commercial insurance.
 7
 8   Q.         DOES      THE     COMPANY            CURRENTLY       HAVE       A    SELF-INSURANCE
 9              PROGRAM?
10   A.         Yes. In fact, the issues addressed in this proceeding cover the changes in the Company's
11              self-insurance reserve subsequent to the settlement in Docket No. 34800 and in the
12              Company's last fully litigated rate case, Docket No. 16705.
13
14   Q.         WHAT DID THE COMMISSION ADOPT REGARDING THE COMPANY'S
15              SELF-INSURANCE EXPENSE IN DOCKET NO. 16705?
16   A.         The Commission granted the Company $1,651,320 per year for current losses and noted
17              the amount should accrue only enough each year to cover typical storm damage. 176 In
18              addition, the Commission did not set a storm reserve balance. The reason the
19              Commission did not set a storm reserve balance is because the Company did not provide
20              a reasonable post test-year level for its then existing reserve fund and because the
21              Company did not prove that the amounts expended in 1997 associated with an ice storm
22              were prudent or appropriate. 177
23
24   Q.         WAS THE ANNUAL STORM LOSS LEVEL MODIFIED RECENTLY?
25   A.         Yes. The Commission recently adopted a settlement in Docket No. 34800 that increased
26              the annual storm loss accrual to $3,651,320 effective January 1, 2009. 178




          176
              Docket No. 16705 FOF 146.
          177
              Id., atFOF 147.
          178
              Docket No. 34800 Settlement Term Sheet Item 8.

                                                                                                    104
         Q.         WHAT DOES THE COMPANY CLAIM HAS TRANSPIRED TO THE STORM
     2              RESERVE SUBSEQUENT TO DOCKET NO. 16705?
     3   A.         The Company claims that it has incurred storm losses from 155 different storms, each of
     4              which exceeded $50,000 of charges in aggregate. 179 In addition, the Company increased
     5              the reserve on an annual basis for the $1.651 million annual insurance accrual through
     6              2008, and then by $3.651 million annually beginning in 2009.
     7
     8   Q.         WHAT ARE THE VARIOUS COMPONENTS OF THE SELF-INSURANCE
     9              RESERVE EXPENSE THAT REQUIRE INVESTIGATION?
    10   A.         The Commission has identified the annual level of contributions until the amount was
    11              increased effective January I, 2009 in association with Docket No. 34800. All other
    12              components that affect the insurance reserve level and annual expense are subject to
    13              review and justification.

    14   2.         Storm Reserve Deficit
    15
    16   Q.         WHAT DOES THE COMPANY CLAIM AS ITS STORM RESERVE DEFICIT?
    17   A.         The Company claims a $64 million deficit or negative reserve currently. 180
    18
    19   Q.         WHAT IS INCLUDED IN THIS RESERVE THAT CAUSES IT TO BE SO
    20              NEGATIVE?
    21   A.         The Company has included all storm-related costs that in aggregate exceeded $50,000 per
I   22              storm. Some of the costs recognized by the Company included incentive compensation,
    23              fire and property insurance premiums, safety training expenses, computer hardware
    24              acquisitions, and, in effect, anything else the Company deems appropriate.
    25
    26   Q.         DID MR. WILSON DEVELOP THE $64 MILLION RESERVE DEFICIT
    27              VALUE?
I   28   A.         No. This amount was provided to him by the Company. 181


I             179
              180
                  Response to Rose City 5-1.
                  Direct Testimony of Mr. Wilson at page 5. The precise claimed deficit is $64,355, 152.
              181
                  Deposition of Mr. Wilson on April 22, 2010 at TR 12.
I                                                                                                          105
 l   Q.          DID MR. WILSON INVESTIGATE THE REASONABLENESS OR NECESSITY
 2               OF ANY OF THE EXPENSES THAT WERE INCLUDED IN THE CLAIMED $64
 3               MILLION RESERVE DEFICIT?
 4   A.          No.182

 5                                                                                                           I
 6   Q.          DID        THE       COMPANY            PRESENT   ANY      DETAILED        ANALYSES
 7               DEMONSTRATING THE VALIDITY OF THE COSTS REFLECTED IN ITS
 8               STORM RESERVE?
 9   A.          No. There was no presentation by the Company that demonstrates it has only included
l0               prudent, reasonable and necessary costs in its storm reserve. In fact, the loss-run data
11               supporting the costs included in the storm reserve for the periods prior to 1996 were not
                           183 Moreover, the Company did not provide any documentation that
12               retained.
13               demonstrates that the labor charges reflected in the storm reserve are not already being
14               recovered through base rate charges and thus may represent a double recovery of
15               expense.
16
17   Q.          AFTER REVIEW OF ALL THE DOCUMENTATION PRESENTED BY THE
18               COMPANY ASSOCIATED WITH ITS STORM RESERVE, DO YOU BELIEVE
19               ADJUSTMENTS ARE NECESSARY?
20   A.          Yes. In my opinion, the Company's claimed $64 million current storm reserve deficiency
21               is quite excessive. In fact, I recommend adjustments to remove the impact of: (1) the
22               major 1997 ice storm; (2) the first $50,000 of each storm corresponding to a deductible
23               that would be in place by standard insurance practices; (3) miscellaneous expenses not
24               appropriately included in the reserve; (4) a proposed situs based adjustment addressed in
25               Docket No. 34800; and (5) additional insurance proceeds associated with securitized
26               storms that have been received or estimated, but which are not reflected in the
27               securitization process or the current filing.




          182
                Id., at TR 12 and 13.
          183
                Response to Cities 30-1 in Docket No. 34800.

                                                                                                      106
     Q.         PLEASE DISCUSS YOUR FIRST ADJUSTMENT RELATING TO THE 1997 ICE
 2              STORM.
 3   A.         Included in the insurance reserve is a charge of $13,014,379 associated with the January
 4              13, 1997 ice storm. 184 This particular storm resulted in a separate docket before the
 5              Commission in which the Company's actions were investigated. That proceeding was
 6              Docket No. 18249. The Order on Rehearing identified the following critical issues or
 7              problems associated with the Company's actions that led, in part, to the significant cost
 8              associated with storm restoration efforts:
 9
10                 •   The Company conceded that it did not have a traditional pole inspection program.
11                     With the Entergy-GSU merger, the Company reduced the number of inspections
12                     for poles. The Company's pole inspection and work cycles were not sufficiently
13                     rigorous, continuous or frequent to maintain all of its facilities in the condition
14                     required to meet its reliability and service obligations under PURA. 185
15                 •   The Company's line maintenance and vegetation control were reactive in nature
16                     and lacked written and specific preventative maintenance policies. Moreover,
17                     priority was not given to capital additions to the detriment of adequate
18                     maintenance practices. 186
19                 •   While the Company claimed that its vegetation management was adequate and
20                     consistent with industry practices, extensive evidence was provided to document
21                     serious neglect of vegetation management. Such serious neglect resulted in
22                     heightened risk to the distribution system associated with the ice storm. "The
23                     Commission concludes that the level of the Company's vegetation management is
24                     unacceptable and has sipiticantly affected the reliability of the distribution
25                     system in recent years." 18
26                 •   The Company itself found it necessary to hire 30 new vegetation clearance crews
27                     subsequent to the ice storm, which only confirmed the existence of an
28                     unacceptable backlog in vegetation control prior to the ice storm. 188
29                 •   "The January 1997 ice storm was certainly a severe storm that would have
30                     diversely affected the best-maintained distribution system. EGS' distribution
31                     system, however, is not the best-maintained. A major cause of the outages during
32                     the storm was broken or bowed ice-laden tree limbs overhanging the wires. Tree
33                     limbs in ROW overhanging distribution lines pose a threat to system reliability
34                     and are largely within EGS' control. The Company's failure to clear the limbs
35                     before the storm was a major factor in the number and duration of outages
36                     experienced by customers. While the Company's initial efforts to mobilize and

          184
              Response to Rose City 5-2.
          185
              Docket No. 18249 Order on Rehearing page 9.
          186
              Id., at pages 9 and 10.
          187
              Id., at page 15.
          188 Id.


                                                                                                      107
 1                deploy non-EGS personnel were slow and caused concern, vegetation
 2                management failures greatly aggravated the situation." 189
 3            •   The Company's management structure is ill-suited to assure best supervision of
 4                the T&D System in the Texas territory. 190
 5            •   The inspection program carried out by the Company was not sufficiently
 6                extensive or adequate to fulfill its proposed purpose of securing reliable
 7                service. 191
 8            •   The Company's distribution system maintenance practices fail to assure
 9                continuance and adequate service to customers. 192
10            •   "Negligent and backlog of vegetation management projects has posed
11                unacceptable risk of increasing and recurrent service outages, especially during
12                major storms." 193
13
14         Moreover, the Proposal for Decision in Docket No. 16705 stated the following regarding
15         the 1997 ice storm:
16
17                First, the ALJs recommend the Commission ignore the $13 million in this
18                case. EGS did not meet its burden to prove that the $13 million
19                expenditure was prudent and reasonable, or even that it was necessary.
20                Cities point out in their Brief that EGS did not inform the other parties that
21                further charges were made to the fund, and EGS did not update discovery
22                requests advising that the reserve was at a level different from the $11.4
23                million. Tr. 6928; 6744-6745 (Lawton). The only information concerning
24                post-test-year charges to the reserve appeared in Mr. Wilson's rebuttal. Tr.
25                8136. On cross-examination, Mr. Wilson testified that he did not know
26                when he first learned that the insurance reserve has been reduced. And he
27                did not review or evaluate the expenditures to determine whether they
28                were prudently incurred, or whether they had been properly expensed and
29                capitalized. Tr. 8800-8803. He did not know if any of the damage could
30                have been avoided by better tree trimming of maintenance of poles. Cities.
31                OPC. and General Counsel suggest. and the ALJs agree. that this issue can
32                be addressed in the 1998 rate filing when all parties will have the
33                opportunity to evaluate the reasonableness of the changes to the insurance
34                reserve fund. 194 (Emphasis added).                                 ·
35
36         The above noted items, along with other items set forth in Docket No. 18249, clearly
37         establish that the Company did not perform adequately or prudently and incurred
38         excessive costs associated with the January 1997 ice storm. Therefore, I recommend that


     189
         Id., at pages 17-18.
     190
         Id., at FOF 26.
     191
         Id., at FOF 45.
     192
         Id., at FOF 46.
     193
         Id., at FOF 82.
     194
         Docket No. 16705 PFD at page 186.

                                                                                                   108
          the Commission exclude the $13 million of ice storm related charges from the
 2        Company's insurance reserve.
 3
 4   Q.   PLEASE DISCUSS YOUR SECOND ADJUSTMENT TO THE COMPANY'S
 5        INSURANCE RESERVE ASSOCIATED WITH DEDUCTIBLE LEVELS.
 6   A.   The Company's self-insurance program fails to comply with standard insurance practices
 7        and in fact, creates a perverse incentive. The issue is the Company's failure to treat the
 8        lower $50,000 threshold as a deductible event. Indeed, with normal insurance policies, an
 9        incentive is provided to the party purchasing insurance to not make unreasonable or
10        frivolous claims. Part of that deterrent is the requirement of a deductible. In this case, the
11        $50,000 minimum threshold employed by the Company should serve the purpose of
12        being the deductible in the insurance process.


13   Q.   HOW SHOULD THE DEDUCTIBLE WORK AS IT RELATES TO THE
14        INSURANCE RESERVE?
15   A.   If the Company incurred $49,999 of expense associated with the storm, it would absorb
16        the entire amount as O&M expenditures. However, if the Company captures one
17        additional dollar of expense, then it converts the process to insurance reserve treatment
18        and includes all expenditures associated with such storm in the insurance reserve, rather
19        than only those amounts in excess of the first $50,000. Regulation must provide
20        reasonable and appropriate incentives in order to minimize costs. The failure to recognize
21        a deductible only encourages the occurrence of costs and provides no incentive to act
22        prudently and in the best interest of customers.
23
24   Q.   IS THERE ANY REASON TO TREAT THE FIRST $50,000 OF STORM COSTS
25        INCURRED AS INSURANCE RESERVE COSTS?
26   A.   No. Failure to treat the first $50,000 of O&M expense related storm expenditures as a
27        deductible insurance practice is inappropriate and must be denied.




                                                                                                    109
 1   Q.         WHAT IS THE IMPACT OF TIDS RECOMMENDATION?
 2   A.         The Company's insurance reserve reflects 155 different storms smce Docket No.
 3              16705. 195 Therefore, after removal of the ice storm previously discussed, I recommend a
 4              reduction to the insurance reserve in the amount of $7,700,000, or 154 times $50,000 per
 5              storm.
 6
 7   Q.         PLEASE ADDRESS THE THIRD AREA OF ADJUSTMENT ASSOCIATED
 8              WITH MISCELLANOUS INAPPROPRIATE CHARGES.
 9   A.         As set forth in the table below, the Company has included numerous charges in its storm
10              reserve that do not comply with the Commission's rule. One of the Commission's rules
11              requires charges only for "property and liability losses which occur, and which could not
12              have been reasonable anticipated and included in operating and maintenance expense." 196


                                          Description                       Amount 1Y 1
                               Incentive Compensation                         $1,002,104
                               Non-Productive Loading                         $1,586,480
                               Fire & Property Insurance                      $3,555,179
                               Computer Hardware Acquisitions                  $487,727
                               Safety Training Loader                          $722,796
                               Total                                          $7,354,286

13              Items such as incentive compensation are not appropriate. Incentive compensation, to the
14              extent that is allowed in base rates in the first place, will not vary depending on whether
15              an employee's time is expended performing normal services or storm reserve related
16              activity. Thus, such charges easily can be anticipated and reflected in O&M expense.
17
18   Q.         IS THE SAME SITUATION TRUE FOR NON-PRODUCTIVE AND SAFETY
19              TRAINING LOADERS AS IS THE CASE FOR INCENTIVE COMPENSATION?
20   A.         Yes. The same is true for non-productive loaders and safety training loaders reflected in
21              the reserve.
22

          195
              Response to Rose City 5-1, including the ice storm.
          196
              P.U.C. Subst. Rule 25.23 l(b)(l)(G).
          197
              Response to Rose City 20-6 and Response to Cities 30-4 in Docket No. 34800.

                                                                                                       110
     1    Q.         CAN THE COMPANY PROVIDE ANY DOCUMENTATION OR SUPPORT FOR
     2               ITS INCLUSION OF HARDWARE ACQUISITION IN THE PROPERTY
     3               INSURANCE RESERVE?
     4    A.         No. The Company was specifically requested to explain in detail and justify the inclusion
     5               of costs associated with computer hardware acquisitions into the property insurance
     6               reserve. The Company's entire response to the request for "all support" was that ''these
     7               charges were related to and deemed necessary for storm restoration." 198 (Emphasis
     8               added). The word "deemed" does not rise to the level of credible support for the inclusion
     9               of computer hardware costs into the storm reserve.
    10
    11    Q.         DO EXPENDITURES FOR FIRE AND PROPERTY INSURANCE PREMIUMS
    12               QUALIFY FOR STORM INSURANCE RESERVE TREATMENT?
    13    A.         No. There is no credible claim that premiums for fire and property insurance are not
    14               reasonably anticipated and includable in operations and maintenance expenses as noted in
    15               the Commission's substantive rules. Indeed, beginning in December of 2007 the
    1.6              Company no longer charged fire and property insurance premiums to its insurance
    17               reserve. 199
    18
    19    Q.         WHAT DO YOU RECOMMEND REGARDING THE COMPANY'S PRACTICE?
    20    A.         I recommend that the $3,555,179 of fire and property insurance premium charges be
    21               removed from the claimed insurance reserve deficit.
    22
    23    Q.         PLEASE DISCUSS YOUR NEXT ADJUSTMENT TO THE INSURANCE
    24               RESERVE BALANCE ASSOCIATED WITH THE COMPANY'S PROPOSED
    25               SITUS ADJUSTMENT.
    26    A.         As part of the Company's presentation of its current storm reserve deficiency, it identifies
    27               a reapportionment of jurisdictional reserve balances due to an analysis during the

I   28               Jurisdictional Separation Plan split.200 As part of this analysis, the Company attempted to




'              198
               199
               200
                   Response to Rose City 21-33.
                   Response to Rose City 21-22.
                   Response to Rose City 5-1 Attachment 1, footnote 2.

                                                                                                             111

I
 1              shift $12,498,325 of charges previously recorded as Louisiana costs to the Texas
 2              jurisdiction.201
 3
 4   Q.         HAS      THE       COMPANY        DEMONSTRATED            THAT       ITS     PROPOSED
 5              ADJUSTMENT IS APPROPRIATE?
 6   A.         No. In fact, the Company's presentation is an after the fact attempt to change the
 7              historical allocation process.
 8
 9   Q.         HAS      THE       COMMISSION        PREVIOUSLY        RECOGNIZED          POTENTIAL
10              PROBLEMS WITH THE COMPANY'S AFTER THE FACT POLICY CHANGES
11              AS IT RELATES TO ALLOCATION OF COSTS BETWEEN JURISDICTIONS?
12   A.         Yes. In Docket No. 34800, the Commission stated the change in the way that the
13              Company allocated its transmission costs is "a policy decision that should be made by the
14              Commission upon consideration of the facts and circumstances that necessitate such a
15              change. " 202 The Commission further stated that without "detailed analysis and findings of
16              fact, the Commission finds it inappropriate to change Entergy's transmission cost
17              allocation methodology as part of this case."203 In other words, the Company must make
18              a strong showing that its policy changes are appropriate before the Commission will
19              permit a shifting of cost previously charged to Louisiana to be reassigned to Texas
20              customers.
21
22   Q.         HAS THE COMPANY PRESENTED A FULL AND COMPLETE ANALYSIS OF
23              ALL JURISDICTIONAL SEPARATION ISSUES IN THIS PROCEEDING?
24   A.         No. Indeed, prior to allowing a change in the historical allocation of costs between
25              jurisdictions for the storm reserve, it is incumbent upon the Company to present and          ...
26              justify that all historical jurisdictional charges are appropriately reflected in the
27              Jurisdictional Separation Plan. Failure to do so could and undoubtedly has resulted in
28              Texas retail customers already paying more than their fair share in comparison to
29              Louisiana ratepayers. Therefore, I recommend that the historical allocation of costs

          201
              Response to Rose City 17-26.
          202
              Docket No. 34800 Order on Remand page 10.
          203 Id.


                                                                                                       112
      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.         I 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 for Adjustment 15
     28              versus 20 years for storm insurance reserve).
     29

               204
                   Response to Rose City 23-21.
               20s Id.
               206
                   Testimony of Mr. Wright at page 20.

                                                                                                            113
 1   Q.         WHAT DO YOU RECOMMEND?
 2   A.          I recommend that the storm reserve deficit balance be adjusted upward (less negative) by
 3               $1,518,978 to reflect the additional funds received, or increased estimates by the
 4              Company, for insurance proceeds relating to Hurricanes Katrina and Rita and by
 5               $3,791,732 for reversal ofETI proposed Adjustment 15.
 6
 7   Q.         WHAT IS THE IMPACT OF YOUR VARIOUS RECOMMENDATIONS TO THE
 8              COMPANY'S            CLAIMED          CURRENT          LEVEL        OF     STORM         RESERVE
 9              DEFICIENCY?
10   A.         The Company claims a $64,355,152 current deficiency in its storm insurance reserve.
11              The adjustments previously discussed total $16,857,757, and reduce the Company's
12              claimed storm insurance reserve deficit to a deficit of $47,497,395.

13   3.         Target Reserve
14
15   Q.         WHAT TARGET RESERVE DOES THE COMPANY REQUEST IN THIS
16              PROCEEDING?
17   A.         The Company proposes to increase the current $15,572,000 target storm reserve to
18               $19,304,000. This represents an increase of$3,732,000 or 24% above the current target.
19
20   Q.          IS THE PROPOSED TARGET SIGNIFICANTLY DIFFERENT FROM THE
21              TARGET LEVEL PROPOSED IN DOCKET NO. 34800?
22   A.          Yes. In Docket No. 34800, Mr. Wilson proposed a $37,110,000 total target amount to the
23               reserve. 207 While, the Company's proposed target level in this proceeding is noticeably
24               less than what was proposed approximately 2 years earlier, it is still excessive.
25
26   Q.          HOW DID THE COMPANY DEVELOP ITS PROPOSED TARGET IN THIS
27               PROCEEDING?
28   A.          Mr. Wilson ran a Monte Carlo simulation on Company loss history. Mr. Wilson
29               performed 5,000 iterations of simulated experience. Based on this simulation, Mr. Wilson

          207
                Direct Testimony of Mr. Wilson page 9 of 18 in Docket No. 34800, but included the anticipated impact of
                 major hurricanes.

                                                                                                                  114


                                                                                                                          I
 l               claims that in any 25-year period, the largest annual expected stonn loss totaling less than
 2               a$100 million is approximately $19.3 million. 208
 3
 4   Q.          DID MR. WILSON RELY ON THE MONTE CARLO ANALYSIS FOR THE
 5               ESTABLISHMENT FOR THE TARGET RESERVE LEVEL IN THE LAST
 6               CASE?
 7   A.          No. Mr. Wilson admitted that he did not use a Monte Carlo analysis in the last
 8               proceeding.209
 9
10   Q.          DOES MR. WILSON'S MONTE CARLO SIMULATION INCLUDE THE
11               IMPACT OF THE PREVIOUSLY DISCUSSED 1997 ICE STORM?
12   A.          Yes.210

13
14   Q.          DID MR. WILSON INVESTIGATE ANY OF THE msTORICAL LOSS DATA
15               REFLECTED IN THE MONTE CARLO SIMULATION?
16   A.          No. Therefore, Mr. Wilson cannot attest to the validity of his database as being
17               reasonable and necessary for ratemaking purposes. As previously discussed, the historical
18               analysis includes charges that are inappropriate for ratemaking purposes and thus,
19               overstates the target level even if it were to be appropriately based on a Monte Carlo
20               simulation.
21
22   Q.          DO THE AMOUNTS REFLECTED IN MR. WILSON'S MONTE CARLO
23               SIMULATION ALSO INCLUDE HURRICANE RELATED COSTS?
24   A.          Yes. While the Company has excluded the majority of hurricane related costs, it has still
25               included over $40 million of hurricane related costs that were not securitized in its
26               analysis. 211




          208
              Direct Testimony of Mr. Wilson at page 10.
          209
              Deposition of Mr. Wilson on April 22, 2010 at TR 30.
          210
              Id., at TR 28.
          211
                Response to OPC 2~ 1O(b).

                                                                                                         115
 1   Q.   DID MR. WILSON NORMALIZE                 ms DATABASE PRIOR TO PERFORMING
 2        THE MONTE CARLO SIMULATION?
 3   A.   No. While Mr. Wilson trended his historical loss data based on inflation considerations,
 4        he failed to nonnalize for any other factors. Other factors include items such as
 5        vegetation maintenance that the Company implemented after the 1997 ice stonn. any
 6        process improvements developed as part of planning for stonn recovery activities, better
 7        software mapping systems of the Company's service territory or other factors that would
 8        change the resulting costs if the same stonn were to occur in the future.
 9
10   Q.   IN YOUR OPINION, IS THE msTORICAL DATABASE ARTIFICIALLY
11        SKEWED TO PRODUCE IDGH..SIDE COST ESTIMATES?
12   A.   Yes. Mr. Wilson's sole efforts associated with attempting to recognize inflation and
13        failing to recognize any other factors that would offset costs results in a skewed database
14        that produces artificially excessive cost estimates.
15
16   Q.   WHAT DO YOU RECOMMEND REGARDING THE TARGET STORM
17        RESERVE LEVEL?
18   A    I recommend retaining the existing target reserve level. The existing target better
19        represents the historical data after adjustment for identifiable excesses reflected in the
20        losses (e.g., the 1997 ice stonn). Further, retention of existing target level also recognizes
21        that other factors (e.g., a more storm hardened system, computerized mapping systems,
22        etc.) other than inflation have changed from historical time periods that should result in
23        lower stonn losses even if the same event were to transpire in the future.
24
25   Q.   WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
26   A.   My recommendation results in a $2,732,000 reduction in the target level reserve. When
27        this amount is amortized over the same 20-year period proposed by Mr. Wilson, it
28        reduces the Company's storm insurance related revenue requirement by $186,600.




                                                                                                    116
 1   4.         Annual Expected Losses
 2
 3   Q.         WHAT DOES THE COMPANY REQUEST FOR ITS EXPECTED ANNUAL
 4              STORM LOSSES?
 S   A.         The Company proposes to accrue $5,270,000 annually in the self-insurance reserve to
 6              cover expected losses for stonns each year. 212 This amount reflects Mr. Wilson's
 7              expectation for annual storm losses, except for those storms over $100 million adjusted to
 8              reflect cummt loss levels.213


 9   Q.         WHAT LEVEL OF ANNUAL EXPECTED STORM LOSSES DID MR. WILSON
10              PROPOSE IN DOCKET NO. 34800?
11   A.         Mr. Wilson proposed an annual accrual of $13,840,000 for expected annual storm
12              losses.214
13
14   Q.         HOW DID MR. WILSON DETERMINE HIS CURRENT $5.27 MILLION
15              ANNUAL STORM LOSS PROPOSAL?
16   A.         Mr. Wilson again relied on the previously noted Monte Carlo simulation of the
17              Company's loss history. 215
18
19   Q.         HOW DOES MR. WILSON'S CURRENT PROPOSAL COMPARE TO WHAT
20              THE COMMISSION HAS PREVIOUSLY ACCEPTED OR ADOPTED FOR
21              ANNUAL STORM LOSS LEVELS?
22   A.         In Docket No. 16705, the Commission adopted a $1,651,320 annual storm loss level.
23              This amount was in place until 2009 when, based on the settlement adopted by the
24              Commission in Docket No. 34800, the annual amount was raised to $3,651,320 annually.
25              Thus, the parties and the Commission believed that a $3.65 million annual storm loss
26              level was reasonable and acceptable as recently as 1 year before the Company filed its
27              current case.

          212
              Direct Testimony of Mr. Wilson at page 7.
          zu Id.
          m Direct Testimony of Mr. Wilson in Docket No. 34800 at page 5.
          215 Mr. Wi1son•s Direct Testimony at page 7.


                                                                                                      117
 1   Q.          HAVE YOU REVIEWED MR. WILSON'S MONTE CARLO SIMULATION,
 2               WIDCll FORMS THE BASIS FOR ms PROPOSAL?
 3   A.          Yes. As previously discussed, the Monte Carlo simulation is a new process employed by
 4               Mr. Wilson. As previously noted, the database relied upon for simulation purposes
 5               includes many significant levels of cost that are inappropriate for ratemaking purposes
 6               and for purposes of predicting reasonable future expectations. In addition, the Company's
 7               analysis fails to recognize any factor other than inflation that can and will impact the
 8               severity of costs incurred in future storms. In addition, Mr. Wilson,s simulation over
 9               estimates the number of storms eligible for inclusion in the stonn reserve, thereby
10               increasing the projected annual total of stonn related O&M expense of reach of his 5,000
11               iterations in his Monte Carlo simulation.
12
13   Q.          HAS THE COMPANY PROVIDED ANY VALID BASIS ON WIDCH TO ADOPT
14               MR. WILSON'S FLAWED MONTE CARLO SIMULATION?
15   A.          No.
16
17   Q.          HAS THE COMMISSION RECOGNIZED THE VALIDITY OF RELYING ON
18               msTORICAL             AVERAGES            AS     A     REASONABLE              APPROACH   TO
19               ESTABLISIDNG EXPECTED ANNUAL STORM WSSES?
20   A.          Yes. In Docket No. 35717, an Oncor Delivery case, the Commission accepted an annual
21               storm. loss expectation based in part on a 10-year average of storm cost values.216
22
23   Q.          IS RELIANCE ON A 10-YEAR msTORICAL AVERAGE REASONABLE IN
24               TIDS CASE?
25   A.          No. Given the significant spike of hurricane activity during the last 5 years, reliance on
26               too short of a historical average skews the reasonably expected results associated with
27               long-term weather conditions. Indeed, just the 2007 value, which includes approximately
28               $25 million of costs associated with Hurricane Humberto, noticeably skews any average
29               that relies on too short of a timeframe to an excessive level for purposes of future
30               projections. The 2007 level associated with Hurricane Humberto is more than 8QG/o

          216
                Docket No. 35717 Final Order at FOF 100 and page 111 of the Proposal for Decision.

                                                                                                           118
 1               greater than the next highest value reported in the Company's database, that being 1997.
 2               As previously noted, the 1997 value includes over $13 million associated with the most
 3               severe ice stonn the Company has ever experienced and which reflects excessive cost
 4               levels due to inappropriate actions by the Company. Removing the 1997 storm-related
 5               activity renders the 2007 Humberto related value at over 1500/o greater than the next
 6               highest value reflected in the Company's 20 plus year historical database. Therefore,
 7               reliance on a I 0-year historical period only serves to artificially inflate the expected
 8               annual storm loss level.
 9
10   Q.          HAVE YOU ANALYZED THE HISTORICAL DATA FROM THE STANDPOINT
11               OF ESTABLISIDNG A REASONABLE ANNUAL STORM LOSS?
12   A.          Yes. Review of the historical data, even on a trended loss basis, but absent the impact of
13               the category 1 Hurricane Humberto, indicates that the current existing $3.651 million
14               annual storm loss accrual would be both reasonable and adequate level for annual storm
15               loss accruals. The reasonableness of the existing annual stonn loss level is especially true
16               taking into considerations that the historical data still contains inappropriate storm loss
17               charges for ratemaking purposes. Indeed, both the IO-year and 20-year average of the
18               trended annual storm loss levels, excluding Hurricane Humberto and the 1997 ice storm
19               costs, each yield approximately the existing $3.651 million annual storm loss expected
20               cost approved by the Commission and agreed to by all parties in Docket No. 34800.217
21
22   Q.          IS THERE ANOTHER CONSIDERATION THAT MUST BE RECOGNIZED IN
23               ESTABLISHING THE ANNUAL STORM LOSS VALUE?
24   A.          Yes. The way the process works is that the annual accrual remains constant until the next
25               rate proceeding. Therefore, the stonn loss reserve was only increased by the $1.651
26               million annual accrual adopted in Docket No. 16705. However, the collection of that
27               amount through base rates is predominantly based on energy charges. Given that there
28               has been growth on the system since 1996, the Company's actually collected through
29               base rates much more than the $1.651 million annual accrual. However, customers have
30               not received the benefit of the annual additional amount that the Company has recovered

          217
                The JO-year average trended loss value is $3.8 million. while the 20-year avenge is $3.6 million.

                                                                                                                    119
 1               through base rates for the insurance reserve annual stonn amounts. Therefore, the higher
 2               the annual storm reserve amount set, the greater amount the Company actually recovers
 3               from customers over time, but for which it does not credit customers. Such amounts
 4               become additional return for the Company, rather than a credit to the insurance reserve.
 5
 6   Q.          WHAT DO YOU RECOMMEND?
 7   A.          Based on the approaches discussed above, I recommend retention of the recently adopted
 8               $3,651,320 annual stonn loss value. This results in a $1,618,680 reduction to the
 9               Company's request.

IO   5.          Minimum Storm Reserve Threshold
11
12   Q.          WHAT IS THE CURRENT STORM RESERVE THRESHOLD?
13   A.          Any storm-related property loss of at least $50,000 is accounted for in the storm
14               reserve. 218
15
16   Q.          WHAT IS THE BASIS FOR THE 550,000 MINIMUM THRESHOLD LEVEL?
17   A.          Other than having been approved prior to Docket No. 16705, the Company could not
18               provide any narrative explanation on how the $50,000 level was detennined.219
19
20   Q.          HOW OFfEN HAS THE COMPANY REVIEWED THE $50,000 THRESHOLD
21               FOR REASONABLENESS?
22   A.          The Company could not identify a single instance in which it has reviewed the $50,000
23               minimum threshold for reasonableness.220




          218
                Response to Rose City 9-2.
          219
                Response to Rose City 9-3.
          220
                Id.

                                                                                                        120
 1   Q.          HAS TIIE COMPANY COMPARED ITS SS0,000 MINIMUM THRESHOLD TO
 2               ANY        OTHER            UTILITIES     FOR     PURPOSES      OF     DETERMINING
 3               REASONABLENESS?
 4   A.          No. The Company states that it "has not compared its stonn      ~rve    policies with any
 5               other utility."22 1
 6
 7   Q.          IS THE SS0,000 MINIMUM TIIRESHOLD REASONABLE?
 8   A.          No. The Company has incurred 155 stonns that it claims qualify for stonn reserve
 9               treatment subsequent to Docket No. 16705.222 This represents in excess of 10 storms per
10               year, not counting Hurricane Rita and Hurricane Ike. Occurrences of this frequency on an
11               annual basis cannot credibly be claimed to comply with the Commission's rules that are
12               intended to allow for storms, "which could not have been reasonably anticipated.',m
13               Moreover, the threshold only encourages the Company to accumulate as many charges as
14               possible associated with, or around, a stonn in order to reach the low $50,000 threshold.
15               By reaching such threshold and attempting to employ stonn reserve treatment, the
16               Company can inappropriately manipulate its annual earnings.
17
18   Q.          DOES THE MINIMUM SS0,000 THRESHOLD COMPORT WITH THE
19               COMMISSION RULE                 AS IT APPLIES TO THE COMPARISON TO
20               COMMERCIAL INSURANCE?
21   A.          No. Indeed, during Mr. Wilson's deposition, he stated that the "deductibles are extremely
22               high" when discussing how insurance companies would set the deductible for the same
23               service.224 Mr. Wilson's statement was made with knowledge of the $50,000 lower
24               threshold for the Company's insurance stonn reserve. Therefore, Mr. Wilson recognizes
25               that insurance compWlies would set a deductible level far in excess of the current $50,000
26               level employed by the Company.




          221   Id.
          222
                Response to Rose City 5-1.
          221
                P.U.C. Subst Rule 25.23 l(bXl)(G}.
          :m Mr. Wilson's deposition on April 22, 2010 at TR 11.

                                                                                                       121
 1   Q.          HAS THE COMMISSION RECENTLY RULED ON THE ISSUE OF WHAT
 2               CONSTITUTES A REASONABLE MINIMUM INSURANCE THRESHOLD
 3               DEDUCTmLE LEVEL?
 4   A.          Yes. In Docket No. 35717, an Oncor Delivery case, the issue as to whether to increase the
 5               minimum threshold level to $10 million was raised. Oncor's witness stated that the
 6               "demarcation point at $500,000 is the hallmark in risk management because losses under
 7               $500,000 are considered routine and predictable. Anything over that loss cannot be
 8               predicted."225 The Commission in Docket No. 35717 accepted the $500,000 minimum
 9               threshold for storm reserve treatment. 226
10
11   Q.          WHAT DO YOU RECOMMEND?
12   A.          I recommend increasing the minimum threshold level from $50,000 per storm to
13               $500,000 per stonn and treating the threshold as a deductible. This level complies with
14               the Commission's rule as it relates to stonns that could not have been reasonably
15               anticipated and is equivalent to what the Commission recently adopted when this issue
16               was contested in Docket No. 35717. This level will further eliminate any unreasonable
17               efforts by the Company to aggregate charges so as to meet the low threshold currently in
18               place and thus remove any incentive for manipulating reasonably predictable O&M
19               expense.
20
21   Q.          WHAT          IS     THE       COMBINED              IMPACT   OF   YOUR      VARIOUS
22               RECOMMENDATIONS?
23   A.          My various recommendations would result in a $3.9 million reduction to the Company's
24               expense request for storm damage reserve and a $45.868 million reduction to rate base.




          225
                Docket No. 35717 Proposal for Decision at page 106.
          226
                Docket No. 357 J7 Final Order FOFs 98-101.

                                                                                                      122
 1   SECTION VI: CASH WORKING CAPITAL

 2   1.         Introduction
 3
 4   Q.         WHAT IS THE ISSUE IN nus PORTION OF YOUR TESTIMONY?
 5   A.         This portion of my testimony deals with       ewe. ewe is a component of rate base and
 6              represents the amount of funds supplied by either the shareholders or others, such as
 7              customers, to fund the day-to-day operations of the Company.
 8
 9   Q.         HOW DID THE COMPANY ARRIVE AT ITS PROPOSED CWC?
10   A.         The Company has attempted to perform a lead-lag study in its efforts to quantify its CWC
11              requirements. The type of study is a cash lead-lag study as required by P.U.C. Subst. R.
12              25.231(c)(2)(BXiii)(IV).
13
14   Q.         WHAT HAS THE COMPANY PROPOSED FOR CWC?
15   A.         The Company has proposed a negative $1,979,613 of CWC.n7 However, the Company
16              has also admitted to two errors relating to state and local franchise fees. 228 The coJTeCtion
17              for those two errors yields a negative $4,869,630 ewe requirement.
18
19   Q.         WHAT LEVEL OF CASH WORKING CAPITAL DID THE COMMISSION FIND
20              APPROPRIATE FOR THE COMPANY IN ITS LAST FULLY LITIGATED
21              RATE CASE?
22   A.         ln Docket No. 16705, the Commission ordered a negative $36,016,000           ewe compared
                                                                                            9
23              to the Company's request for a negative $8,053,000 CWC in that casen In other words,
24              the Commission found errors and made adjustments that more than quadrupled the
25              negative level of   ewe requested by the Company.         My testimony in that case, upon
26              which the Commission relied in part, also addressed various errors and inappropriate
27              positions taken by the Company.



          227 Schedule E-4 page 2.
          228
              Response to State of Texas 8-9.
          229
              Docket No. 16705 Final Order Schedules lV and Vl.

                                                                                                          123
 l   Q.   PLEASE SUMMARIZE YOUR RECOMMENDATIONS IN TIUS PROCEEDING
 2        AS IT RELATES TO YOUR REVIEW OF THE COMPANY'S ewe REQUEST.
 3   A.   The Company's negative ewe estimate is again substantially inadequate {i.e. too little
 4        level of negative CWe). A more appropriate level ofCWC is a negative $45.7 million or
 5        $43. 7 million more negative than the Company's original request as set forth on Schedule
 6        {JP-4).     While, again in this case, there are many problems associated with the
 7        Company's lead-lag study, I have attempted to correct mainly the major components and
 8        make adjustments to comport with Commission precedent A summary of the specific
 9        areas and issues follows.
10
11           •      Meter·To-Billing Revenue Lag. In spite of expenditures for electronic meter
12                  reading equipment, new computer hardware and software, the Company proposes
13                  a longer period of time necessary to read a meter and issue a bill than in the past
14                  This attempt to rely on a longer period of time signifies that the Company
15                  believes it has become less efficient. The regulatory principle that customers
16                  should not shoulder the burden of the Company's inefficiencies must be
17                  recognized in the lead-lag study. Relying on a meter-to-billing period previously
18                  achieved by the Company results in $4,973,701 more negative ewe.
19
20           •      BiUing-To-Payment Revenue Lag. The Company relies upon an inappropriate
21                  methodology to estimate the time period between when it bills a customer and
22                  when a customer pays their bill. Moreover, Company's estimation process
23                  reflects the unusual affect of the worldwide financial meltdown that began in the
24                  last quarter of 2008. In addition, the Company proposes a 60-day lag for its MSS-
25                  4 affiliate transaction. My recommended methodology relies on a previously
26                  accepted approach, with a modification that will eliminate a concern raised by the
27                  Commission in Docket No. 16705, and removal of the MSS-4 affiliate transaction
28                  results in $26.2 million more negative ewe.
29
30           •      Customer Float Revenue Lag. The Company proposed a customer float revenue
31                  lag of 0.95 days for its retail revenues based on an estimation it believes to be
32                  reasonable. The Company's estimation is based on customer count rather than
33                  revenues. When revenues are used for the calculation, the float days decline to
34                  0.49 days. The adjustment to the Company's proposed customer float results in
35                  $1.6 million more negative ewe.
36
37           •      Payroll Expense Lead. The Company's proposed lead-lag study does not
38                  conform to Commission precedent in Docket No. 16705 as it relates to the service
39                  period associated with vacation pay. The Company's attempt to ignore the
40                  Commission's decision in Docket No. 16705 stems from its illogical and
41                  inappropriate attempt to inconsistently measure the service period for expenses as

                                                                                                   124
     1               a period when the expense is recorded rather than when the product or service is
     2               provided. In addition, the Company also failed to properly recognize the deferred
     3               compensation aspect associated with incentive compensation. Reversal of the
     4               Company's attempt to not follow the Commission's previous order relating to
     5               vacation pay and proper treatment of incentive pay results in $6.3 million more
     6               negative ewe.
     7
     8           •   FAS 106 Expense Lead. In Docket No. 16705, the Commission adopted a
     9               312.55 day expense lead for FAS 106 expenses. The Company again ignores that
    10               decision by excluding the expense. This is another instance where the Company
    11               attempts to employ an illogical and inconsistent approach in order to artificially
    12               increase revenue requirements. Complying with Commission precedent on this
    13               issue results in $2.2 million more negative ewe.
    14
    15           •   Entergy Services, Inc. Expense Lead. The Company has proposed 38.04 lead
    16               days for this category of CWC. The Company bases its lead day proposal on its
    17               operating agreement with Entergy Service, Inc. That agreement permits payment
    18               no later than the 25th of the following month. The major problem with the
    19               Company's analysis is its failure to recognize that a substantial component of the
    20               amount at issue is associated with incentive compensation. Proper recognition of
    21               the extended lead days associated with incentive compensation results in $5.6
    22               million of more negative ewe.
    23
    24           •   Other O&M Expense Leads. As was the case in prior dockets, the Company
    25               has made errors in its stratified sample of invoices used to determine the
    26               appropriate expense leads for other O&M. Correction of certain problems in the
    27               Company's current stratified sample analysis increases the expense lead days by
    28               15.52 days resulting in $3.6 million of more negative ewe.

    29        Due to the interactive nature between revenue lags and expense leads, the combined
    30        impact of the above various adjustments is not simply the addition of each individual

r   31        component.    Rather, the combined impact is $45.7 million, or $43.7 million more
    32        negative CWC as set forth on Schedule (JP-4).
    33

    34   2.   General
    35
    36   Q.   WHAT ISALEAD-LAGSTUDY?
    37   A.   A lead-lag study is an attempt to measure the value of the difference between the time the
    38        Company provides services to its customers and the time it receives payment for such
    39        services, compared to the time the Company receives a product or service and the time it


                                                                                                    125
 1              pays for such product or service. As part of the lead-lag study, an attempt is made to
 2              measure the revenue lag and compare it to an expense lead. 230
 3
 4   Q.         WHAT ARE THE COMPONENTS OF THE REVENUE LAG?
 5   A.         Within the revenue lag component of a lead-lag study there are four components: the
 6              service period, the billing lag, the collection lag, and the financial or customer lag. The
 7              service period normally represents the mid-point of the month in which service is
 8              provided. The billing lag represents the time period between the date a meter reading is
 9              taken and a bill is issued to the customer. The collection lag is the period between the
I0              time the Company issues a bill to the customer and the date the customer pays the
11              Company. Finally, in instances where the Company receives payment in a form other
12              than cash or electronically, it is considered a :financial lag until funds become available.
13
14   Q.         WHAT ARE THE COMPONENTS OF THE EXPENSE LEAD?
15   A.         Normally for an electric company, the largest single component of expense leads is its
16              cost of energy, whether it is through self generation (e.g., coal, oil, gas, or nuclear) or
17              through purchase power costs. Other components are labor, other O&M, property taxes,
18              etc. The Company has identified many categories as set forth on Schedule E.
19
20   Q.         IS THERE A MAJOR ISSUE REFLECTED IN THE COMPANY'S CONCEPT OF
21              A LEAD-LAG STUDY THAT IS CONTRARY TO COMMISSION PRECEDENT?
22   A.         Yes. Company witness Mr. Gallagher states that "a central issue in the measurement of
23              both revenue and expense payment lags is a consistent definition of the Service Period -
24              i.e., the date the utility provides services to its customers for which it incurs costs and
25              accrues revenues and expenses. 231 (Emphasis added).                   Unfortunately, while Mr.
26              Gallagher desires consistency, the Company's practice, with his oversight, is anything but
27              consistent.
28
          230
                                                                                                                          I
              The revenue lag represents the claimed time period between date(s) the Company provides service to
               customers and the date(s) the Company receives funds from the customer for such service. An expense
               lead is the time period between the date(s) the Company receives a product or service and the date(s) it
               pays for such product or service.
                                                                                                                          I
          231
              Direct Testimony of Mr. Gallagher at page 8.

                                                                                                                  126     I
     1               Mr. Gallagher's discussion of service period between expenses and revenues violates
     2               prior Commission decisions as well as logic and consistency.             In particular, Mr.
     3               Gallagher would have the Commission believe that it is logical and consistent to measure
     4               the revenue lag as the time period during which customers receive service. For example,
     5               if a customer's meter readings occur on April and May 1st, the service period is one
     6               month or 30 days. On average, the customer will have received the service 15 days into
     7               the 30-day period. This concept of service period has nothing to do with the fact that the
     8               recording of the actual revenues that will be charged to the customer do not occur until
     9               later in May when the billing process is completed. Alternatively, Mr. Gallagher would
    10               have the Commission believe that the service period associated with expenses occurs
    11               only when the recording of labor, materials or other costs occur. In other words, he
    12               would have the Commission believe that the Company has not received a product or
    13               service until it accrues or books the expense not when it receives a product or service.
    14               This inconsistent logic between revenue and expense service periods must be recognized
    15               for what it is, a direct attack on the Commission's prior decisions and a clear indication
    16               of the Company's desire to artificially minimize the negative level of CWC that should
    17               be reflected in rate base.

    18   3. Revenue Lag

    19               A.      Meter Reading To Billing
    20
    21   Q.          WHAT HAS THE COMPANY PROPOSED FOR ITS METER READING TO
    22               BILLING REVENUE LAG?

I   23
    24
         A.          The Company proposes 3.63 days associated with its Customer Information System
                     ("CIS") related customers and 3.72 days for large power customers. 232

i   25
    26   Q.          ARE THESE REASONABLE LEVELS?

l   27   A.          No.   The Company has invested money into electronic meter reading devices and
    28               expensive computer systems that incorporate billing systems. One would hope that the

l   29               expenditures of large amounts of capital on such equipment and software would result in

              232
                    Company Work.paper WP/E-4 page 3.

                                                                                                            127
 1              recognizable benefits for customers given that customers must pay a return of and a
 2              return on such investments. Unfortunately in this area, the Company has become less
 3              efficient in the billing process in spite of such substantial capital expenditures.
 4
 5   Q.         HAVE       OTHER       REGULATORY            BODIES       RECOGNIZED           THE      MORE
 6              EFFICIENT BILLING PROCESS ASSOCIATED WITH MORE MODERN
 7              ELECTRONIC METER READING DEVICES AND BILLING SYSTEMS?
 8   A.         Yes. The Railroad Commission of Texas ("RCT'). the regulator of gas utilities in Texas,
 9              has adopted a I -day meter reading to billing lag for the largest gas utility in the state. 233
10              Moreover, the RCT adopted such shorter period of time in spite of the gas utility's
11              request to increase the number of days so as to permit verification of potential erroneous
12              billings. 234 The adoption of that position was based, in part, on my testimony in those
13              proceedings. The guiding principle for the RCT decision was that customers "should not
14              be punished if a utility decides to manage the business process and payment less
15              efficiently."235
16
17   Q.         IS THE RCT'S GUIDING PRINCIPLE A REASONABLE AND APPROPRIATE
18              STANDARD?
19   A.         Yes. If the Company elects to allow inefficiencies in the billing process that results in
20              higher cost to customers, then such costs should be borne by shareholders, not customers.
21              As previously noted, the customers are already paying for equipment and software that
22              provide the capability of performing the billing process in a much more efficient manner.
23              Moreover, this Company has demonstrated that it can and has completed the meter
24              reading-to-billing process in as little as 1.46 days for the equivalent to the CIS customer
25              class which comprises the majority of customers and revenues. 236




          233
              RCT GUD 9869, Atmos Gas Company.
          234
              RCT GUD No. 9670 Final Order FOF 126, and GUD No. 9902.
          235
              RCT GUD No. 9670 Final Order at FOF 148.
          236
              Company Workpaper WP/E-4 page 26 of 47 in Docket No. 12852 also set forth as Exhibit (JP-16) in Mr.
               Pous' Testimony in Docket No. 16705.

                                                                                                             128
 1   Q.   WHEN YOU STATE THAT THE METER READING-TO-BILLING PERIOD
 2        HAS     INCREASED         RATHER        THAN      DECREASED,          ARE      YOU     JUST
 3        REFERRING TO THE 1.46 DAY PERIOD PREVIOUSLY REFERENCED?
 4   A.   No. While it obviously has increased from Docket No. 12852, it has also increased from
 5        Docket No. 16705 where the Company proposed a 3.61-day meter reading-to-billing lag.
 6        It is apparent that the Company, absent proper direction from this Commission to
 7        demonstrate that it will not tolerate inefficiencies in the billing process, will have a
 8        perverse incentive to perfonn in a manner that is detrimental to customers. In fact, the
 9        Company has every incentive to be inefficient in this particular area because it earns a
10        full rate of return on the higher level of cash working capital due to its own inefficiencies.
11        The continuation of this situation is neither reasonable nor equitable.
12
13   Q.   WHAT DO YOU RECOMMEND?
14   A.   I recommend that the Commission follow the lead of the RCT and adopt a principle that
15        customers "should not be punished if the utility decides to manage the business process
16        and payment less efficiently." The Company's incentive to operate inefficiently by
17        earning a higher return is neither reasonable nor appropriate.            The Company has
18        demonstrated that it can issue a CIS bill within 1.46 days after reading meters. The
19        largest gas utility in the state has demonstrated that it can read meters and bill either on
20        the same day or within one day and has its base rate set on a 1-day meter reading to
21        billing period. Customers are paying for investment in meter reading devices, computers,
22        and software that make it possible to perform the meter reading process in a more
23        efficient manner. Customers are entitled to the benefit of the bargain associated with
24        such expenditures. Based on the various items noted above, I conservatively recommend
25        that a 1.46 day meter reading-to-billing lag for CIS related customers be adopted. This is
26        a level that the Company has demonstrated that it can achieve even prior to its investment
27        in the newer meter reading devices, computers, and software.




                                                                                                    129
 l   Q.         WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
 2   A.         My recommendation on a standalone basis would result in a $4,973,701 more negative
 3              CWC requirement than what the Company proposed.237

 4              B.      Billing-To-Payment Revenue Lag
 5
 6   Q.         WHAT BAS THE COMPANY PROPOSED FOR THE REVENUE LAG DAYS
 7              ASSOCIATED WITH THE PERIOD BETWEEN ISSUING BILLS AND
 8              RECEIVING PAYMENT FROM CUSTOMERS?
 9   A.         The Company has identified 4 separate revenue lag periods for this component of the
10              lead-lag study. The Company has proposed 22.26 days for its CIS customers, 16.21 days
11              for its large power customers, 60 days for MSS-4 sales, and 20 days for its other affiliated
12              sales.238
13
14   Q.         DO YOU TAKE ISSUE WITH ANY OF THE COMPANY'S PROPOSALS?
15   A.         Yes. I take issue with the Company's proposed 21.80 days for its CIS customers which
16              comprise approximately 53% of the entire revenues, and the 60-day lag proposed for
17              MSS-4 affiliate revenues. 239
18
19   Q.         WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSED 21.80 REVENUE
20              LAG DAYS FOR ITS CIS CUSTOMERS?
21   A.         The Company relies on an inconsistent accounts receivable turnover niethod. 240 As will
22              be discussed later, the Company attempts to relate an end of month amount of accounts
23              receivable to daily average revenues.
24
25   Q.         IS THE COMPANY'S OVERALL APPROACH TO THE BILLING TO
26              COLLECTION REVENUE LAG DAYS APPROPRIATE?
27   A.         No. While the Company's actual mechanics has problems, the overall process employed
28              by the Company is inaccurate.           The Company relies on an end of month accounts                     I
          237
              Schedule E-4 page 2 of 2 average daily amount of $4,324,957 times l .15 days (3 .63-1.46) X .528732.
          238
              Company Workpaper WP/E-4 page 3.
          239
              Company Workpaper WP/E-4 page 3.
          240
              Id, at page 17.

                                                                                                                     130
     1              receivable balance and compares that to the average daily revenues. The problem with
     2              this approach rests on the premise that the end of month accounts receivable balance is
     3              equivalent to the individual daily accounts receivable balances throughout the month.
     4              Given that the Company has 21 different billing cycles throughout the month, the
     5              accounts receivable monthly ending balance is skewed towards customers billed in the
     6              later billing cycles and does not reflect the relationship experienced by those customers
     7              billed in the early billing cycles of the month who have already paid their bill and are no
     8              longer reflected in accounts receivable at the end of the month.
     9
    IO   Q.         HAS THE COMPANY'S APPROACH RECENTLY BEEN TESTED IN TEXAS?
    11   A.         Yes. In RCT Docket No. 9670, Atmos Energy, the state's largest gas company, proposed
    12              the same approach. The RCT found that such approach was unacceptable based in part
    13              on my testimony. Distortions can occur due to the difference between daily accounts
    14              receivable balances compared to a month end accounts receivable balance in a turnover
    15              analysis.   This problem can result in several revenue lag days of difference in the
    16              Company's billing-to-collection lag.
    17
    18   Q.         HAS THE COMPANY'S BILLING-TO-COLLECTION LAG CHANGED OVER
    19              TIME?
    20   A.         Yes. While the Company proposes 21.80 days in this proceeding for its CIS customers, it
    21              proposed only 19.02 days in Docket No. 30123. 241 Moreover, in Docket No. 16705 the
    22              Company proposed 21.63 days and in Docket No. 12852 the Company proposed 19.6
    23              days. 242 It also proposed 19.67 days in Docket No. 20150 and 22.26 days in Docket No.
    24              34800. 243 Therefore, the Company's proposal in this proceeding represents its second
\
    25              highest requested value over the past numerous rate proceedings and is 1.48 days greater
    26              than the level in place during Docket No. 12852 and 1.41 days greater than the 19.67
    27              billing-to-payment revenue lag in Docket No. 20150.



              241
                  Docket No. 30123 Company Workpaper WP/E-4 page 2.
              242
                  Docket No. 12852 Company Workpaper WP/E-4 page 26 of 47.
              243
                  Workpaper WP/1-A-1-111.1 AJ12-1 in Volume 40-VL at page 838 in Docket No. 22356 and Workpaper
                   WP/E-4 page 4 in Docket No 34800.

                                                                                                           131
 1   Q.          DID YOU SEEK INFORMATION NECESSARY TO QUANTIFY A MORE
 2               ACCURATE            BILLING-TO-COLLECTION             REVENUE        LAG     FOR     THE
 3               COMPANY IN THIS CASE?
 4   A.          Yes. I sought the Company's daily accounts receivable balances for retail sales, the
 5               aging of accounts receivable reports for each month of the test year, and the daily revenue
 6               receipts during the test year. The Company does not maintain all such information. 244
 7
 8   Q.          IS THERE AN ADDITIONAL PROBLEM WITH RELYING ON THE
 9               ACCOUNTS RECEIVABLE DATA EMPLOYED BY THE COMPANY?
10   A.          Yes. The test year data includes the period during which this country, if not the world,
11               experienced a financial meltdown and was on the brink of financial collapse. Credit dried
12               up for both individuals and companies. Reliance on this period, August 2008 and for an
13               extended period thereafter, unrealistically skews the revenue lag upward. Therefore, even
14               if the Company's proposed approach were relied on, which it should not be, it is
15               excessively high due to the period contained in the analysis.
16
17   Q.          CAN YOU PROVIDE AN EXAMPLE OF THE DISTORTION CAUSED BY
18               RELYING ON DATA CORRESPONDING TO THE PERIOD OF ECONOMIC
19               TURMOIL?
20   A.          Yes. A proxy for the impact can be seen from the month end accounts receivable reports
21               for October 2008 and 2009. The October 2008 report identified $1,353,134 of arrears for
22               the 90-day category, while the same value for October 2009 was only $200,111. The 90
23               days in arrears level of accounts receivable during the thick of the financial meltdown
24               was almost 7 times the level one year later. 245 There were similar situations in other
25               arrears categories.


                                                                                                                1
                                                                                                                J

          244
                Response to Cities 9-18.
          245
                Response to Cities 9-6.

                                                                                                          132
 1   Q.         GIVEN THE CIRCUMSTANCES THE COMPANY HAS PRESENTED, WHAT
 2              DO YOU RECOMMEND?
 3   A.         The Company's current request is obviously incorrect and cannot be relied upon.
 4              Unfortunately, the Company was unable to provide necessary information associated
 5              with the current test year as it pertains to daily accounts receivable balances or even daily
 6              revenues. Therefore, I recommend a modified aging of accounts receivable approach
 7              adopted in Docket No. 16705.
 8
 9              In Docket No. 16705, the Company provided aging of accounts receivable information.246
10              I recommended an adjustment in that proceeding relying on that information, with one
11              assumption not adopted by the Commission.                That assumption was that for those
12              customers under the current pay category, I assumed a conservative 14-day period while
13              the Commission rules allow up to 16 days.247 The examiners denied this approach since
14              they could "find no reason to justify changing the Commission-required 16-day paid
15              schedule."248 However, the examiners did say they questioned "whether the disconnects
16              really tipped the balance to 16."249 While I still believe that the 14-day assumption was
17              conservative given that all customers who are current do not pay on the very last day
18              possible, I base my recommendation in this case on adopting the full 16-day payment
19              period allotted by the Commission. In other words, I modified the values set forth on
20              Schedule (JP-17) page 1 of2 in Docket No. 16705 and increased the revenue lag days for
21              the current balances from 14 to 16 days. Increasing the payment period assumption to the
22              absolute maximum permitted by the Commission rules would increase my previously
23              proposed 18.66 revenue lag days to 20.38 days (an additional 1.72 days to reflect 2
24              additional days time for 85.97 % of customers that pay currently).




          246
              Docket No. 16705 Company response to Cities 97 - 1 as shown on Schedule (JP-17) in that case.
          247
              PUC Subst. R. 25.28.
          248
              Docket No. 16705, PFD at Section F 2 (a).
          249 Id.


                                                                                                              133
 l   Q.   DO YOU BELIEVE TIDS APPROACH IS MORE REPRESENTATIVE THAN
 2        THE COMPANY'S PRESENTATION?
 3   A.   Yes, and for the various reasons noted above, the Company's position is in error. The
 4        Company's position is not only excessive but unsupportable. The Company has elected
 5        not to maintain the type of data that would permit a more accurate current calculation.
 6        Moreover, the Company's proposal is approximately 2.5 days greater than what it has
 7        proposed in several prior proceedings. In comparison, my proposed 20.38 days is less
 8        than half the difference between what the Company has previously proposed and what it
 9        currently proposes and is based on real Company data associated with aging of accounts
10        receivable information utilizing the most conservative assumption for current billings.
11
12   Q.   DO YOU BELIEVE YOUR ESTIMATE IS TOO CONSERVATIVE?
13   A.   Yes I do. However, given the examiners concerns in Docket No. 16705 and the current
14        situation that the Company has placed both the interveners and Commission in, I find that
15        this conservative approach should cure any concern the Commission previously had in
16        Docket No. 16705 on this issue. Moreover, to the extent the Commission was so inclined
17        and elects to adopt my previous position based on an average 14-day payment period
18        versus the full 16 days permitted under the rule, then the revenue lead would need to be
19        reduced by an additional 1.72 days, or $3,933,198.
20
21   Q.   WHAT IS THE IMPACT OF YOU RECOMMENDATION?
22   A.   My recommendation of a 20.38 bill-to-payment revenue lag for the CIS class results in a
23        $3,243,718 reduction to rate base (1.42 days x $4,324,957 x 52.8732%).
24
25   Q.   WHAT IS THE ISSUE WITH THE COMPANY'S PROPOSED 60-DAY BILLING
26        TO PAYMENT PERIOD FOR MSS-4 SALES?
27   A.   Cities' witness Mr. Garrett recommends the removal of the EGSL Sabine and Lewis
28        Creek MSS-4 sales transactions from the Texas retail cost of service. Therefore, I have
29        removed this component from the revenue lag.                                                    I
                                                                                                          I
                                                                                                    134
I
i    1   Q.         WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
     2   A.         My recommendation results in a $14.4 million reduction to CWC requirements. 250

     3              c.     Customer Floa t

I    4
     5   Q.         WHAT HAS THE COMPANY REQUESTED FOR THE REVENUE LAG DAYS
     6              ASSOCIATED WITH THE CUSTOMER FLOAT CATEGORY?
     7   A.         The Company has proposed a lag of0.95 days for the CIS and Large Power categories. 251
     8
     9   Q.         WHAT DOES THIS AMOUNT REPRESENT?
    10   A.         The Company states this amount represents the check float corresponding to the period
    11              that funds from payment by customers are not available to the Company because checks
    12              for payments have not cleared from the customers accounts to the Company's account. 252
    13
    14   Q.         WHAT IS THE COMPANY'S BASIS FOR THE 0.95 DAY REQUEST?
    15   A.         Mr. Gallagher states that "it ap_pears that after taking into account immediate cash
    16              available from electronic funds transfer" that a 0.95 weighted lag days for retail sales is
    17              appropriate. 253 (Emphasis added).
    18
    19   Q.         HAS THE COMPANY JUSTIFIED ITS REQUESTED CUSTOMER FLOAT?
    20   A.         No. First, the Company's proposal is based on customer count and not dollars. 254
    21
    22   Q.         IS IT APPROPRIATE TO RELY ON A CUSTOMER COUNT RATHER THAN
    23              ON THE CORRESPONDING REVENUES?
    24   A.         No. Indeed, the revenue float is quite different from what Mr. Gallagher proposes. The
    25              Company admits that at least 51 % of its revenues were received in the form of cash, wire




              250
                  Total revenue lag days decline to 39.84 ifMSS-4 revenues are removed. This represents a 3.33 reduction in
                   revenue lag days from ETI's proposed level of 43.17 days (3.33 x $4,324,957 = $14,408,915).
              251
                  Company Workpaper WP/E-4 page 3.
              252
                  Mr. Gallagher's Direct Testimony at page 13.
              253
                  Company Workpaper WP/E-4 pages 14-16.
              254
                  Company Workpaper WP/E-4 page 7.

                                                                                                                       135
                                                                                                              I
 1               transfer or other electronic manners. 255 Recognition of cash and electronic payments by     1
 2               dollar amount rather than by count reduces the 0.95 check float to 0.49.
 3                                                                                                            I
 4   Q.          WHAT DO YOU RECOMMEND?
 5
 6
     A.          I recommend the Company's request for a 0.95-day customer float be denied.
                 Company's request is based on the wrong factor (customer count rather than revenues).
                                                                                                       The    I
 7               Therefore, I recommend a 0.49-day check float lag for the CIS and Large Power classes.       I
 8
 9   Q.          WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
10   A.          My recommendation for a 0.49-day customer float reduces rate base by $1,612,822
11               ((0.95-0.49) x $4,324,957 x 81.06753%).
12
13   Q.          WHAT IS THE NET IMPACT OF YOUR VARIOUS REVENUE LAG
14               RECOMMENDATIONS?
15   A.          The adoptions of the revenue lag adjustments that I have recommended would reduce the
16               Company's overall revenue lag days from 43.17 days to 37.12 days or 6.05 less revenue
17               lag days. A 6.05 reduction in revenue lag days would result in a reduction to rate base of
18               $26,169,306 based on the Company's requested level of expenses.

19   4. Expense Leads

20               A. Payroll
21
22   Q.          WHAT HAS THE COMPANY PROPOSED FOR EXPENSE LEAD DAYS
23               ASSOCIATED WITH PAYROLL?
24   A.          The Company proposes 14.55 lead days for the expense lead. 256




          255
                Response to Rose City 9-12.
          256
                Company Work.paper WP/E-4 page 2.

                                                                                                       136
 1   Q.          IS THE COMPANY'S PROPOSED PAYROLL EXPENSE LEAD DAYS IN
 2               COMPLIANCE WITH THE COMMISSION'S ORDER IN DOCKET NO. 16705?
 3   A.          No. In Docket No. 16705 at FOP 114, the Commission adopted the position I sponsored
 4               in that case. In doing so the Commission stated that "recognizing vacation time as a
 5               separate component of payroll to account for the lag between when the employee earns
 6               vacation time and when the Company pays for it in salary expense" is reasonable.
 7               Unfortunately the Company• s calculation in this case fails to recognize the significant
 8               incremental time period associated with vacation pay.257
 9
10   Q.          DOES THE COMPANY IDENTIFY ANY CHANGED CIRCUMSTANCES THAT
11               WARRANT THE REVERSAL OF THE COMMISSION'S PRECEDENT ON
12               THIS ISSUE?
13   A.          No.
14
15   Q.          WHAT DID YOU RECOMMEND FOR THE EXPENSE LEAD ASSOCIATED
16               WITH VACATION THAT WAS ADOPTED BY THE COMMISSION IN
17               DOCKET NO. 16705?
18   A.          As set forth in my testimony in Docket No. 16705 at page 99, I recommended a 210.67
19               day period as the appropriate expense lead days for vacation pay.
20
21   Q.          DO    YOU      STILL     BELIEVE       THIS     LEVEL       IS   REASONABLE          AND
22               APPROPRIATE?
23   A.          Due to the change in relationship of vacation pay to total payroll, I am of the opinion the
24               recommended level is conservative.
25
26   Q.          WHAT LEVEL OF VACATION PAY DID THE COMPANY INCUR DURING
27               THE TEST YEAR IN THIS PROCEEDING?
28   A.          The Company incurred $3,842,535 of vacation pay for the test year. 258




          257
                Company Workpaper WP/E-4 page 164.
          258
                Response to Rose City 9-16 .

                                                                                                        137
 1   Q.         HOW DID YOU ADJUST THE COMPANY'S PROPOSED PAYROLL EXPENSE
 2              .LEAD DAYS FOR THE PROPER RECOGNITION OF VACATION PAY?
 3   A.         I began with the Company's payroll of $35,210,377. 259 I then subtracted the test year
 4              vacation pay amount of $3,842,535. 260 Next, I applied a 210.67 lead day period to
 5              vacation pay. I then applied the Company proposed 13 day payroll lead period to the
 6              remaining payroll. I then added the Company proposed 1.23 lag days for the withholding
 7              lag. This results in 35.81 lag days for payroll, or an adjustment of 21.57 days and a
 8              reduction to rate base of $2,080,974.
 9
10   Q.         IS THERE A SECOND ISSUE RELATING TO THE PAYROLL EXPENSE LEAD
11              DAYS?
12   A.         Yes. The second issue deals with incentive compensation.
13
14   Q.         IS THERE A DEFERRED PAYMENT ASSOCIATED WITH INCENTIVE
15              COMPENSATION?
16   A.         Yes. Just as the situation for vacation pay there is also a deferred payment associated
17              with incentive compensation.
18
19   Q.         WHAT IS THE DEFERRED PERIOD OF TIME ASSOCIATED WITH
20              PAYMENT OF INCENTIVE COMPENSATION?
21   A.         The Company paid its annual incentives on March 12, 2009 for calendar 2008 services. 261
22
23   Q.         WHAT LEVEL OF LEAD DAYS DID THE COMPANY ASSIGN TO INCENTIVE
24              COMPENSATION?
25   A.         The Company assigned the same 13 day lead it assigned to all other payroll, prior to the   I
26              impact of withholding items. 262
                                                                                                           1

          259
              Company Work.paper WP/E-4 page 294.
          260
              Response to Rose City 9-16.
          261
              Response to Rose City 7-l(E).
          262
              Company Work.paper WP/E page 164.

                                                                                                    138
 1   Q.         IS THERE ANY REASON NOT TO RECOGNIZE THE MARCH 12111 OF THE
 2              FOLLOWING YEAR AS THE APPROPRIATE DEFERRED PAYMENT DATE?
 3   A.         No. The Company's action is based on the same illogical and inconsistent opinion of Mr.
 4              Gallagher that assumes that the service period for expenses begins when an expense is
 5              recorded. This false opinion must be corrected.
 6
 7   Q.         WHAT IS THE APPROPRIATE NUMBER OF LEAD DAYS FOR INCENTIVE
 8              COMPENSATION?
 9   A.         The appropriate number of lead days for incentive pay is 253.5 days. This level of lead
10              days is based on the average service period of the prior year (365/2) plus 71 days
11              corresponding to January 1 through March 12 of the following year.
12
13   Q.         HOW DID YOU CALCULATE THE IMPACT OF TIDS ADJUSTMENT?
14   A.         I employed the same methodology that I discussed for vacation payroll.          The only
15              difference is that I use $3,688,868 corresponding to the level of incentive
16              compensation.263 This process resulted in a 39.43-day increase in the payroll lead days.
17              This incremental addition is additive to the vacation payroll adjustment.
18
19   Q.         WHAT IS THE IMPACT OF TIDS ADJUSTMENT?
20   A.         Increasing the overall net payroll lead days from 14.23 days to 25.20 days results in more
21              negative working capital of$2,430,616.

22              B.      FAS 106
23
24   Q.         WHAT DOES THE COMPANY PROPOSE FOR LEAD DAYS ASSOCIATED
25              WITH FAS 106 EXPENSES?
26   A.         The Company proposes to exclude this expense from its analyses. 264 It should be noted
27              that the Company also claims it reflected the impact in the "Other O&M" expense
28              category. 265


          263
              Response to Rose City 7-l(E) ..
          264
              Direct Testimony of Mr. Gallagher at page 18.
          265
              Response to Rose City 24-55.

                                                                                                      139
 1
 2   Q.          IS THE ELIMINATION OF FAS 106 IN COMPLIANCE WITH THE
 3               PRECEDENT SET IN THE COMPANY'S LAST FULLY LITIGATED RATE
 4               CASE?
 5   A.          No. The Commission's order in Docket No. 16705 found that FAS 106 expense is a form
 6               of deferred compensation and should have a 312.55 day lead assigned to it.
 7
 8   Q.          WHAT ARE FAS 106 EXPENSES?
 9   A.          FAS 106 expenses represent post retirement benefits other than pensions. In other words,
10               these amounts represent an employee benefit provided as part of an overall compensation
11               package. FAS 106 costs are deferred compensation.
12
13   Q.          DO YOU AGREE WITH THE COMPANY'S DECISION TO EXCLUDE FAS 106
14               EXPENSE FROM THE ANALYSIS?
15   A.          Of course not, and neither did the Commission in Docket No. 16705. Mr. Gallagher's
16               presentation in this proceeding is anything but clear or logical. First, he testifies that FAS
17               106 expenses are not cash expenditures and excluded from his analysis, but then claims
18               that they are treated as "Other O&M" expense. Mr. Gallagher also fails to even reference
19               the fact that FAS 106 expenses are deferred compensation.                Thus, just as this
20               Commission has recognized vacation pay as deferred compensation requiring extended
21               number of lead days in comparison to normal payroll days, the same is true for FAS 106
22               expenses.    There is no reason to vacate the Commission's precedent on this matter,
23               especially given the Company's presentation in this proceeding. There are no changed
24               circumstances. There is no underlying support or logic to conclude anything other than
25               cash payments are being made for FAS 106 expenses, that they are a component of
26               ewe, and that they represent deferred compensation.
27
28   Q.          WHAT DO YOU RECOMMEND?
29   A.          I recommend following the Commission's precedent on this matter.              In Docket No.
30               16705 the Commission recognized that such costs are deferred compensation and adopted
31               my recommended 312.55 expense lag days for this category of expense.266

          266
                Schedule (JP-15) page 2 of2 in Docket No. 16705.

                                                                                                           140
     1   Q.         WHAT IS THE IMPACT OF YOUR RECOMMENDATION?
     2   A.         Given that the Company has proposed $2,522,308 of FAS 106 expense for the test year,
     3              in conjunction with the 312.55 expense lead days I am recommending, results in a
     4              standalone impact of$2,159,856 of more negative ewe requirement. 267

     5              C.     Entergy Services Inc. ("ESI") Expense Lead
     6
     7   Q.         WHAT LEVEL OF LEAD DAYS DID THE COMPANY PROPOSE FOR
     8              ENTERGY SERVICE EXPENSES?
     9   A.         The Company proposes an expense lead of 39.30 days for expenses associated with
    10              Entergy Services, Inc. expense. 268
    11
    12   Q.         WHAT IS THE COMPANY'S BASIS FOR ITS PROPOSED 39.30 LEAD DAYS?
    13   A.         Mr. Gallagher at page 17 of his direct testimony states that the ETl/ESI Service
    14              Agreement requires payments for ESI services to be made in the month after the expenses
    15              are booked. The payment of these costs occur between the 20th and 25th of the month
    16              following the provision of service. The actual calculation of the proposed lead days is set
    17              forth in the Company's workpapers. 269
    18
    19   Q.         DO YOU AGREE WITH THE COMPANY'S PROPOSAL?
    20   A.         No. A substantial portion of the Company's charges from Entergy Services, Inc. is
    21              associated with incentive compensation. In fact, during the test year, $9,481,590 of ESI
    22              charges were attributable to incentive compensation. 270 As previously noted, incentive
    23              compensation represents a form of deferred compensation. Therefore, the incremental

I   24              lead days associated with incentive compensation must be added to the portion of ESI
    25              charges that are incentive compensation related.       The Company pays its incentive

t   26              compensation on or about March 15th of the year following the period used to determine
    27              whether incentive compensation has been earned. A March 12th payment yields 253.5
    28              lead days compared to the standard payroll levels reflected in the ESI charges of 13 days.

              267
                  Response to Rose City 24-55.
              268
                  Company Workpaper WP/E-4 page 2.


'
r
              269
              270
                  Company Workpaper WP/E-4 page 764.
                  Response to Rose City 6-4 through 6-10.

                                                                                                           141
 1              Therefore, an incremental 241.5 days must be recognized for the incentive compensation
 2              portion of the ESI charges.
 3
 4   Q.         WHAT IS THE STANDALONE IMPACT OF YOUR RECOMMENDATION?
 5   A.         Segregation of the ESI related incentive compensation charges from the total ESI
 6              expenses reflected in the    ewe analysis, along with the application of a 253.5 lead day
 7              period for such incentive compensation results in an incremental negative working capital
 8              of $5,564,276.

 9              D.     Other O&M Expense Lead
10
11   Q.         WHAT DID THE COMPANY PROPOSE FOR OTHER O&M EXPENSE LEAD
12              DAYS?
13   A.         The Company proposed 28.55 days plus 3.84 days for check float, or a total of 32.39
14              days. 271 This level is 11.75 shorter than the 44.14 expense lag days Mr. Gallagher
15              supported in Docket No. 34800. 272 In other words, the value in the last case was 36%
16              higher than the current proposed value.
17
18   Q.         HOW DID THE COMPANY ESTABLISH ITS OTHER O&M LEAD DAY
19              PROPOSAL?
20   A.         The Company performed a stratified random sample process of 140 invoices. 273
21
22   Q.         WHAT IS A STRATIFIED SAMPLE?
23   A.         A stratified sample represents a situation where the variance in a population is recognized
24              by segregating the individual sample items into various stratums or categories that
25              represent different size intervals. In this case the Company recognized that the dollar
26              level of its invoices range from a few dollars to over $240,000. Therefore, it elected to
27              establish different dollar ranges with the highest stratum for invoices over $100,000 and
28              the lowest stratum for invoice amounts less than $250.


          271
              Company Workpaper WP/E-4 page 2.
          272
              Id., in Docket No. 34800.
          273
              Testimony of Mr. Gallagher at page 19.

                                                                                                       142
     1   Q.          HAVE YOU REVIEWED THE SAMPLE AND THE COMPANY'S PROPOSED
     2               RESULTS FROM SUCH SAMPLE?
     3   A.          Yes.    As was the situation in prior cases, the Company has made several errors in
     4               performing its sample analysis for the other O&M category.
     5
     6   Q.          WHAT TYPE OF ERRORS DOES THE COMPANY'S PROPOSAL REFLECT?
     7   A.          The Company incorporated prepayments in its sample. Prepayments are already or should
     8               be reflected in rate base in the prepayment category of rate base. The Company also paid
     9               invoices early in order to capture a discount. Unfortunately, the discount taken was so
    10               small that the Company's actions actually cost customers more than the discount, if not
    11               corrected. Customers should not pay for imprudent financial decisions. There are also
    12               instances where Mr. Gallagher did not capture the correct service period reflected on the
    13               invoice in his sample.
    14
    15   Q.          CAN YOU PROVIDE AN EXAMPLE OF EACH TYPE OF ERROR?
    16   A.          Yes. For sample item number 8 in the greater than $100,000 stratum, the Company
    17               incurred an invoice with a September 1, 2008 through August 31, 2009 service period.
    18               The Company paid that invoice on November 13, 2008 and attempts to claim a negative
    19               99-day lead. 274 The payment represents a prepayment and should be excluded from the
    20               ewe analyses.
    21
    22               An example of the Company's inefficient financial actions can be seen on sample item 9
    23               in the greater than $100,000 stratum. This particular vendor offers a 0.7% discount if the

I   24
    25
                     invoice is paid within 15 days. The vendor also provides for no discount or penalty if
                     payment is made within 45 days, or 30 more days. The invoice was for $126,190 and by

I   26
    27
                     paying early the Company received an $883.33 discount. Unfortunately, by paying early
                     the Company now wants customers to incur a loss of 1.45 lead days for the greater than

I   28
    29
                     $100,000 stratum. 275 Since the greater than $100,000 stratum represents 32.59% of the
                     total stratums, the failure to take full advantage of the 45 day net terms for this single

I             274
                    Company Workpaper WP/E-4 pages 828 and 878-880.
              275
                    $126,190 x .993/$2,599,973.62 x 30 days= 1.45 days.

                                                                                                           143
 1              invoice caused the Other O&M category lead days to be understated by 0.47 days (l.45 x
 2               0.3259). A loss of 0.47 lead days for this Other O&M category that has a $233,838
 3              average daily balance increases rate base by $109,904 ($233,838 x 0.47). Using a 12%
4                grossed-up overall cost of capital for illustrative purposes yields a $13,188 increase in
 5               revenue requirements. In other words, the Company saved customers $883.33 by taking a
 6               discount, but wants to charge them $13,188 for its efforts. This is not appropriate.
 7
 8               An example of Mr. Gallagher's failure to capture the correct service period can be seen
 9              on sample item 13 in the $25,000 to $50,000 stratum. This particular invoice clearly
10               identifies the service period by stating ''for services from 5/31/2008 to 6/27/2008."276
11               Unfortunately, Mr. Gallagher relied on a July 2, 2008 date as the service period. 277
12
13   Q.         WHAT IS THE IMPACT OF THE VARIOUS CORRECTIONS THAT YOU
14              RECOMMEND TO THE OTHER O&M LEAD DA VS PROPOSED BY MR.
15               GALLAGHER?
16   A.          As set forth on Schedule (JP-5), the numerous recommended corrections to the Other
17               O&M category increase the Company proposed 28.55 lead days to 44.07 lead days.


18   SECTION VII:                RIVER           BEND         DECOMMISSIONING                   REVENUE
19               REQUIREMENT
20
21   Q.          WHAT IS THE ISSUE IN TIDS PORTION OF YOUR TESTIMONY?
22   A.          This portion of my testimony addresses the Company's request for decommissioning
23               expense revenue requirements associated with River Bend. To the extent the Commission
24               has authority to address this issue, I recommend that the Company's request for a $2.8
25               million decommissioning expense annual revenue requirement be reversed and the
26               existing $0-level of decommissioning expense be retained.




          276
                Company Workpaper WP/E-4 page 1026.
          277
                Id., at page 972 for sample number 13.

                                                                                                         144
     1   Q.          WHY DO YOU STATE THAT THE COMMISSION MAY NOT HAVE
     2               AUTHORITY              TO          RULE    ON   DECOMMISSIONING               REVENUE
     3               REQUIREMENT MATTERS?
     4   A.          It is my understanding that Cities' witness Mr. Brazell will be addressing this issue as to
     5               whether the Commission has authority to impact a FERC established tariff. However, to
     6               the extent that the Commission believes it has authority to address this issue, I
     7               recommend the retention of the $0-level of decommissioning expense revenue
     8               requirements.
     9
    10   Q.          WHAT DOES THE COMPANY REQUEST REGARDING DECOMMISSIONING
    11               REVENUE REQUIREMENTS?
    12   A.          Mr.    Gillam states that the Company is requesting $2.8 million of annual
    13               decommissioning expense. 278 lbis represents a $2.8 million increase from the existing
    14               $0-level of expense.
    15
    16   Q.          WHAT IS THE COMPANY'S BASIS FOR REQUESTING A $2.8 MILLION
    17               REVENUE REQUIREMENT FOR DECOMMISSIONING ACTIVITIES?
    18   A.          The existing $0-level of decommissioning expense is predicated on Item 9 of the
I   19               Settlement Term sheet in Docket No. 34800. Item 9 states that nuclear depreciation and
    20               decommissioning amounts reflect the life extension of River Bend. In other words, while
    21               the Company has not formally received the 20-year life extension from the NRC for
    22               River Bend, it did recognize the impact of such extension for ratemaking purposes in its
    23               settlement of Docket No. 34800. Now in this case, Mr. Gillam bases his analysis for
    24               decommissioning revenue requirements on the initial 40-year life span versus a 60-year
                                                  279
    25               life span for River Bend.
    26
    27   Q.          IS THE COMPANY'S REVERSAL OF POSITION APPROPRIATE?
    28   A.          No. The industry as a whole has embarked on and received approval for 20-year license
    29               extensions for various nuclear power plants. Indeed, Entergy Corporation has already


              278
                    Direct Testimony of Mr. Gillam at page 3.
              279
                    Gillam Exhibit PEG-3.

                                                                                                            145
 1               received 20-year license extensions for nuclear units and is in the process of seeking 20-
 2               year license extensions for several other nuclear generating facilities. In addition, the
 3               NRC has been given a formal notice that a license extension will be requested for the
 4               River Bend station. Thus, the industry, the Company's parent, and the Company all
 5               recognize the change in life expectancy for nuclear generating facilities such as River
 6               Bend.
 7
 8   Q.          HOW DID MR. GILLAM DEVELOP ms $2.8 MILLION ESTIMATE?
 9   A.          Mr. Gillam developed an analysis that reflected estimation of future decommissioning
10               costs, earning rates for different types of external funds, cost escalation rates,
11               management fee levels, as well as other variables. Mr. Gillam estimated these variables
12               through the year 2034, or approximately 25 years into the future. 280
13
14   Q.          HOW DOES THE 20-YEAR LIFE EXTENSION AFFECT THE CALCULATION
15               EMPLOYED BY MR. GILLAM?
16   A.          Given that the Company's earnings rate for its trust funds are higher than its estimated
17               cost escalation rates yields the straightforward conclusion that a 20-year life extension
18               will reduce the need for additional customer funding of the external trust funds
19               requirements. In other words, estimated earning rates of 4.51 % and higher are greater
20               than the assured 4.25% cost escalation rate. Therefore, the further out into the future the
21               decommissioning process is moved the lesser is the need for further customer
22               contribution to the external funds.




                                                                                                               I
                                                                                                               I
          280
                Direct Testimony of Mr. Gillam at pages 4-6, and Exhibit PBG-3 .

                                                                                                        146
                                                                                                               '
     1   Q.         ARE THERE PROBLEMS WITH MR. GILLAM'S ANALYSES PRIOR TO
     2              RECOGNITION OF A 20-YEAR LIFE EXTENSION FOR RIVER BEND?
     3   A.         Yes. Mr. Gillam relies on an excessive Texas retail allocation factor (i.e., 42.73% versus
     4              42.5%). 281 Mr. Gillam's analysis also understates the starting balance of both external
     5              funds by millions of dollars. 282 In addition, Mr. Gillam only addresses future assumed
     6              cost escalation for decommissioning activities and fails to address productivity gains or
     7              other cost reduction factors.
     8
     9   Q.         HAVE       YOU       ANALYZED         THE     IMPACT        ON      THE      EXPECTED
    10              DECOMMISSIONING REVENUE REQUIREMENT FUNDS FOR A 20-YEAR
    11              LIFE EXTENSION?
    12   A.         Yes. Recognition of a 20-year life extension for the River Bend station would eliminate
    13              the Company's $2.8 million requested revenue requirements for decommissioning.
    14              Recognition of the 20-year life extension in conjunction with the correction noted above
    15              would further result in the fact that Texas retail customers have already overpaid their
    16              annual decommissioning funding requirements.
    17
    18   Q.         HAVE      TEXAS        CUSTOMERS         BEEN      TREATED        FAIRLY       IN    THE
    19              DECOMMISSIONING FUNDING PROCESS?
    20   A.         No. Even though ETI is responsible for approximately 42.5% of River Bend and EGSL is
    21              responsible for approximately 57.5%, the same situation does not exist for the
I   22              decommissioning fund balance. As of December 31, 2009, Texas retail customers' trust
    23              fund balance was $101 million out of the total $153.5 million balance. 283 Thus, while
    24              Texas retail customers have only 42.5% of the plant they have contributed 66% of the
    25              total decommissioning fund balance. In other words, Texas retail customers have
    26              historically done what was thought to be the "right thing" and contributed to the fund in a
    27              responsible, but excessive, manner.
    28

              281
                  Id., at Exhibit PBG-3.
              282
                  Response to Rose City 10-3.
              283
                  Response to Rose City 10-3 and 10-2.

                                                                                                           147
 1   Q.          HAVE TEXAS RETAIL CUSTOMERS BEEN REWARDED FOR DOING THE
 2               "RIGHT TIIlNG"?
 3   A.          No. As stated elsewhere in my testimony, the nation as well as the world experienced a
 4               financial meltdown in the second half of 2008. Due to the dramatic declines in the equity
 5               markets Texas retail customers lost more money than their counterparts in Louisiana.
 6               Indeed, Company witness Mr. Caruso stated that ''the jurisdiction that has accumulated
 7               the most balance [Texas retail customers] is going to have a bigger share of the gain or
 8               loss."284 Mr. Caruso was right, Texas retail customers have suffered to date much more
 9               than their counterparts in Louisiana. First they paid more, then lost more in the
10               worldwide financial meltdown in 2008, and now are being asked to make up for those
11               losses. The Company's decommissioning trust fund treatment of Texas retail customers
12               has not been equitable compared to Louisiana customers.
13
14   Q.          WHAT DO YOU RECOMMEND?
15   A.          I recommend the retention of the current $0-level of decommissioning expense. The 20-
16               year life extension and correction of certain errors would eliminate the Company's
17               request. Additional factors must also be considered. First, even slight increase in the
18               earnings rates or slight decline in the cost escalation factor would further eliminate the
19               need for any current contribution. Indeed, EGSL employs a 2.5% decommissioning cost
20               escalation factor in Louisiana and a 5.7% earnings growth rate. 285 If either of these
21               factors were employed in Texas, the result would be further support for a $0-level of
22               decommissioning accrual. Next, any recognition of gains in productivity would also
23               reduce the need for any further decommissioning contributions. This concept is
24               significant given the decommissioning cost estimate have a built in contingency factor.
25               The only necessary contingency factor is time itself. As more time passes, and there is                  I
26               more than 35 years until the 20-year life extension expires, costs, productivity, earnings
27               and other factors will be known with greater certainty. Another consideration for totally                I
28               eliminating the requested revenue requirements is the fact that if the actual
29               decommissioning process were delayed for a short period, after retirement, it would result

          284
                 Deposition of Mr. Caruso on April 29, 2010 at TR 54.
          28
               s Entergy Corporation August 13, 2009 letter to the NRC regarding the "Decommissioning Funding Assurance
                  Plans."

                                                                                                                   148
     1        in the current fund levels being even more excessive. Therefore, there is no reason to
     2        change the current contribution level at this time.



     3   SECTION VIII:        RIVER BEND DEPRECIATION RATES
     4
     5   Q.   WHAT IS THE ISSUE IN TIDS PORTION OF YOUR TESTIMONY?
     6   A.   The Company has included a River Bend depreciation analysis in its filing. City witness
     7        Mr. Brazell will address whether the Commission has authority to set a depreciation rate
     8        for the River Bend station. However, to the extent the Commission does set depreciation
     9        rate, the rate proposed by the Company must be reduced to reflect the elimination of
    IO        interim retirements and a 20-year license extension.
    11
    12   Q.   WHAT DEPRECIATION RATE DOES THE COMPANY REQUEST FOR RIVER
    13        BEND?
    14   A.   As set forth in Company witness Mr. Spanos' Exhibit JJS-2, the Company seeks a
    15        composite depreciation rate for its nuclear plant investment of 3.6%. This rate is
    16        comprised of individual rates for the individual plant accounts and reflects the
    17        recognition of interim retirements, an ELG calculation procedure, and a 40-year life span
    18        rather than a 60-year life span.
    19
    20   Q.   ARE THE RATES PROPOSED BY THE COMPANY APPROPRIATE AND

I   21
    22   A.
              REASONABLE?
              No. As previously noted under the depreciation section of my testimony, the Commission
    23        has historically denied the inclusion of interim retirements. The current rates for River
    24        Bend do not reflect the impact of interim retirements. In addition, also discussed in the
    25        depreciation section of my testimony, the use of the ELG depreciation procedure is
    26        inappropriate. Finally, the life span proposed by the Company is artificially short based
    27        on the available facts.




                                                                                                   149
 1                          RIVER BEND DEPRECIATION RATES


                                Account          ETI        Cities
                                  321          2.99%        1.33%
                                  322          3.67%        1.53%
                                  323          4.24%        1.66%
                                  324          3.14%        1.32%
                                  325          5.03%        2.10%
                                 Total         3.36%        1.42%

2         As can be seen in the table above, the 20-year life extension and elimination of interim
3         retirements significantly reduces the necessary depreciation rates and depreciation
4         expense requested by the Company by $26,671,803 for the Texas jurisdiction based on
5         plant as of December 31, 2008.
6
7    Q.   DOES TillS CONCLUDE YOUR TESTIMONY?
 8   A.   Yes. However to the extent I have not addressed an issue, method, procedure, etc., that
9         should not be construed that I am in agreement with the Company's issue, method,
10        procedure, etc.




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