
TEXAS COURT OF APPEALS, THIRD DISTRICT, AT AUSTIN





NO. 03-03-00428-CV



Cities of Corpus Christi, et al., (1) Appellants//AEP Texas Central Company; Public Utility
Commission of Texas; and Constellation New Energy, Inc., Cross-Appellants

v.

Public Utility Commission of Texas and AEP Texas Central Company, Appellees//Public
Utility Commission of Texas; Cities of Corpus Christi, et al.; Office of Public
Utility Counsel; and Constellation New Energy, Inc., Cross-Appellees





FROM THE DISTRICT COURT OF TRAVIS COUNTY, 261ST JUDICIAL DISTRICT

NO. GN104182, HONORABLE SUZANNE COVINGTON, JUDGE PRESIDING



O P I N I O N 


	This case presents three sets of issues arising from Texas's transition from a wholly
regulated retail electricity market.  First, we will consider the extent to which the Public Utility
Commission had power to order electric utilities to refund alleged "over-mitigation" of their stranded
costs, as determined from interim computer models, before the final 2004 true-up proceedings. 
Second, we will determine whether substantial evidence supports the Commission's characterization
of Nuclear Electric Insurance Limited (NEIL) account balances as generation-related rather than
transmission-related.  Third, we will address whether the Commission may set demand charges for
large commercial customers greater than those it set before deregulation.  Because we determine that
the Commission exceeded its statutory authority in ordering refunds of "over-mitigated" stranded
costs determined before the 2004 true-ups, we will reverse the portion of the district court's
judgment compelling such refunds and remand to the Commission for further proceedings. 
However, we will affirm the district court's judgment affirming the Commission's disposition of the
issues concerning NEIL member accounts and demand charges.

GENERAL BACKGROUND

	Finding that "the production and sale of electricity is not a monopoly warranting
regulation of rates, operations, and services and that the public interest in competitive electric
markets requires that, except for transmission and distribution services and for the recovery of
stranded costs, electric services and their prices should be determined by customer choices and the
normal forces of competition," in 1999 the legislature enacted comprehensive 
legislation--commonly known by its bill number, S.B. 7--providing for an ordered transition from
Texas's former wholly regulated electricity market to a more competitive retail electricity market. 
See Act of May 27, 1999, 76th Leg., R.S., ch. 405, 1999 Tex. Gen. Laws 2543, 2543-2625 (codified
at Tex. Util. Code Ann. §§ 39.001-.910 (West Supp. 2004-05); Tex. Util. Code Ann. § 39.001(a);
In re TXU Elec. Co., 67 S.W.3d 130, 132 (Tex. 2001) (Phillips, C.J., concurring).  In several of our
prior opinions, we have described the basic steps in this transition.  See, e.g., Reliant Energy, Inc.
v. Public Util. Comm'n, 101 S.W.3d 129, 133-36 (Tex. App.--Austin 2003), rev'd in part sub nom
CenterPoint Energy, Inc. v. Public Util. Comm'n, 143 S.W.3d 81 (Tex. 2004); Reliant Energy, Inc.
v. Public Util. Comm'n, 62 S.W.3d 833, 835-36 (Tex. App.--Austin 2001, no pet.).  Under the
former regulatory regime, each region of the state was served by a single vertically integrated utility
that generated electricity, built and maintained the electricity distribution "wires" or grid, and sold
the electricity to consumers at retail, all under the comprehensive regulation of the Public Utility
Commission (Commission).  Under S.B. 7, these utilities were required to "unbundle" themselves
into three separate entities--a power generation company, a transmission and distribution utility, and
a retail electric provider.  Tex. Util. Code Ann. § 39.051(b).  Power generation companies provide
wholesale generation services in competition with other generators entering the market.  In re TXU,
67 S.W.3d at 132 (Phillips, C.J., concurring).  Retail electric providers (REPs) provide retail electric
service to end-use customers in competition with other REPs.  Id.  Transmission and distribution
utilities (TDUs) own and maintain the "wires" used to transport electricity from the power generation
companies to all REPs and retail consumers in the utility's geographic service area.  Id.  Because the
legislature continued to regard TDU's as monopolies within their respective service areas, their rates
continued to be regulated by the Commission.  See Tex. Util. Code Ann. § 39.001(a), (b).  A utility
could "unbundle" through the creation either of separate unaffiliated companies or of separate
affiliated companies owned by a common holding company ("affiliated companies" or "unbundled"
companies), or through the sale of assets.  Id. § 39.051(c). 
	Other aspects of the legislatively-mandated transition to a more competitive electricity
market gave rise to the issues in this appeal.  We explore each of these aspects below with its
corresponding issues.
STRANDED COSTS

	AEP Texas Central Company (AEP) brings three issues on appeal concerning the
Commission's order regarding stranded costs.  We will first review the nature of stranded costs and
the Commission's decision to order credits to refund "over-mitigation" before the 2004 true-up.  We
will then turn to the specifics of AEP's issues.

Nature of stranded costs
	Although "stranded costs" have a precise, technical definition under chapter 39 of the
utilities code, id. § 39.251(7), the supreme court has generally described them "as the portion of the
book value of a utility's generation assets that is projected to be unrecovered through rates that are
based on market prices."  In re TXU, 67 S.W.3d at 132 (Phillips, C.J., concurring) (quoting City of
Corpus Christi v. Public Util. Comm'n of Tex., 51 S.W.3d 231, 238-39 (Tex. 2001)).  The largest
part of stranded costs are attributable to investments in nuclear power plants.  See id.
	Stranded costs are a potential byproduct of Texas's transition from the former rate-regulated electricity system to competition.  Under the former system, the Commission could set
rates that would enable utilities to recover from consumers the costs of their generation-related
assets.  Utilities accordingly made considerable investments in generation-related assets with the
expectation of being able to recover the costs of these investments and a reasonable return.  See
CenterPoint Energy, Inc. v. Public Util. Comm'n of Tex., 143 S.W.3d 81, 82 (Tex. 2004). 
Theoretically, the existence of these costs would, upon the beginning of competition, create
significant competitive disadvantages for incumbent utilities relative to new market entrants. 
Because the new market entrants would not have these embedded generation-related costs and
opportunity cost reflected in the rate of return, their pricing structure would tend to be lower than
those of incumbent utilities.  This, in turn, would enable new market entrants to price electricity
below a level at which incumbent utilities could recover their investments.  See id.  Hence,
incumbent utilities would either have to charge uncompetitive higher rates or simply absorb these
"stranded costs."  See id. at 82-83. (2)
	The legislature thus gave careful attention to the issue of stranded costs when
considering deregulation of the electricity market.  The April 1998 Report to the Texas Senate
Interim Committee on Electric Utility Restructuring contained an estimate of projected potential
stranded costs, described as "excess cost over market," or "ECOM," for nine Texas incumbent
utilities as of December 31, 2001, the last day before retail competition would begin.  These "1998
ECOM Report"estimates were derived from computer models that took account of factors, such as
the cost of fuel used to power generating plants, that would impact the market value of generating
assets. 
	The legislature determined that, among its other foundational findings regarding
electricity deregulation, it is in the public interest to "allow utilities with uneconomic generation-related assets and purchased power contracts to recover the reasonable excess costs over market of
those assets and purchase power contracts."  Tex. Util. Code Ann. § 39.001(b)(2).  It established a
three-phase regulatory program intended to assist incumbent utilities in recovering or eliminating
what otherwise would have been stranded costs in the competitive market.  In re TXU, 67 S.W.3d
at 132 (Phillips, C.J., concurring).
	Under the first phase, which ended on December 31, 2001, the Commission froze
retail electric rates ("freeze period").  Tex. Util. Code Ann. § 39.052; In re TXU, 67 S.W.3d at 133
(Phillips, C.J., concurring).  Utilities that had been identified as having potential stranded costs in
the 1998 ECOM Report were allowed to "mitigate" them by (1) shifting depreciation from the
transmission and delivery assets to the generating assets, Tex. Util. Code Ann. § 39.256 (West Supp.
2004-05), and (2) accelerating the cost recovery of stranded costs each year through the use of
legislatively-approved "tools."  Id. § 39.254 (West Supp. 2004-05); see also id. §§ 39.251-.265. 
Among the tools offered, the legislature set means for computing during the rate-freeze period
positive annual revenues, annual costs, and invested capital.  Id. §§ 39.257-.259.
	Under the second phase, from January 1, 2002, to December 31, 2003, the
Commission was to determine whether any stranded costs remained to be recovered by entering
updated data into the ECOM model.  Id. § 39.201(a), (b)(3), (g), (h); In re TXU, 67 S.W.3d at 133
(Phillips, C.J., concurring).  Based on these calculations, the Commission was authorized to consider
any remaining stranded costs in setting the "competition transition charge" or "CTC."  Tex. Util.
Code Ann. § 39.201(b)(3).  The CTC is intended to cover a utility's stranded costs through collection
from every customer taking power over the utility's transmission and delivery system, thus making
up the difference between a generating plant's book value and its market value.  In re TXU, 67
S.W.3d at 133 (Phillips, C.J., concurring).  At the same time, the legislature set the rates each
affiliated REP was allowed to charge residential and small commercial customers (3) at six percent less
than the rate charged on January 1, 1999.  Tex. Util. Code Ann. § 39.202(a) (West Supp. 2004-05)
("price to beat").  Rates of competing unaffiliated REPs and of affiliated REPs for large commercial
and industrial customers were not subject to the price to beat.  See id.  The legislature required the
utilities to file their proposed tariffs with the Commission by April 1, 2000 (during the freeze
period).  Id. § 39.201(a).  They were also to supply supporting cost data for determining
"nonbypassable delivery charges," including data establishing estimates of stranded costs "that are
reasonably projected to exist on the last day of the freeze period."  Id. § 39.201(b), (g), (h). 
	Under the final phase, stranded costs are to be calculated in "true-up" proceedings
beginning January 2004.  Values generated at a "true-up" will emerge from market valuations of a
utility's generation assets, based on stock prices and anticipated income streams in a competitive
market, as determined by updating the 1998 ECOM model.  Id. §§ 39.201(l), 39.262(h), (i).  If
stranded costs remain, the Commission can extend the CTC collection period or increase the charge. 
Id. §§ 39.201(l), .262(c).  At the utility's option, it may securitize (4) any or all of the stranded costs. 
Id. § 39.262(c).  Conversely, if the Commission finds in the true-up proceeding that the competition
transition charge is larger than is needed to recover any remaining stranded costs, the commission
may reduce the competition transition charge, reverse, in whole or in part, the depreciation expense,
reduce the transmission and distribution utility's rates; or implement a combination of these efforts. 
Id. § 39.201(l). 

Generic unbundled cost-of-service docket
	In March 2000, the nine incumbent electric utilities in Texas, including Central Power
and Light Company (the unbundled utility that owned the TDU that ultimately became AEP), filed
applications with the Commission proposing rates based on a 2002 test year, and the Commission
instituted separate contested case proceedings for each.  See 16 Tex. Admin. Code § 25.344(d)
(2005); In re TXU, 67 S.W.3d at 133 (Phillips, C.J., concurring).  Because the nine dockets shared
many of the same legal and policy issues concerning stranded costs, among other issues not now on
appeal, the Commission concluded that a supplemental generic proceeding would be the most
efficient method for resolving these common issues.  Common issues resolved in the generic docket
were then applied in each individual docket.  The cases are generally referred to as the "unbundled
cost of service" or UCOS cases. 
	The Commission segmented each individual docket into four phases.  In Phase I, the
Commission conducted a hearing on the business separation plan through which the utility proposed
to divide itself into a power generation company, a transmission and delivery company, and an
affiliated retail electric provider.  In Phase II, the Commission conducted a hearing to project the
amount of the utility's stranded costs when retail competition began on January 1, 2002.  See Tex.
Util. Code Ann. § 39.201(g).  In Phases III and IV, the Commission conducted hearings to determine
the actual rates the transmission and delivery company could charge REPs.  In re TXU, 67 S.W.3d
at 133 (Phillips, C.J., concurring). 
	Identified in the 1998 ECOM Report as one of the utilities likely to have stranded
costs, AEP had implemented procedures to mitigate its stranded costs by reducing the book value
of its assets by the amount of its excess earnings.  As a result of evidentiary hearings and the input
of updated data into the ECOM model, in October 2001 the Commission revised its stranded-cost
estimate for AEP to be negative $615.066 million. (5)  In other words, the Commission determined that
the continuation of AEP's mitigation efforts would result in an over-mitigation of $615.066 million
by the time of the 2004 true-up.  Because AEP had been utilizing mitigation tools from 1999 until
2001, the Commission applied its new data to AEP's earnings report and determined that AEP had
recovered actual excess earnings in the amount of $54.789 million by 2001.
	Based on its determination from the 2001 interim ECOM calculations that several
utilities had over-mitigated stranded costs, the Commission set a generic docket to decide the
question of its authority to act with respect to the excess mitigation earnings.  The Commission
acknowledged that chapter 39 of the utilities code does not describe any method for addressing over-recovery of stranded costs before the 2004 true-ups.  However, it determined that it could order
utilities to refund the over-recovery of stranded costs it had determined through the interim ECOM
estimates, relying on language in the first sentence of the section governing the 2004 true-up that
"[a]n electric utility . . . may not be permitted to overrecover stranded costs through the procedures
established by this section or through the application of the measures provided by the other sections
of this chapter." (6) See Tex. Util. Code Ann. § 39.262(a).  In AEP's individual case, the Commission
then ordered AEP to refund those amounts through a credit ("excess mitigation credit" or "over-mitigation credit") in transmission and distribution rates to the REPs, amortized over five years.  It
also decided that, if AEP is found at the 2004 true-up to have stranded costs after having refunded
"over-mitigated" amounts, AEP could not recover interest on the over-refunded amounts.
	AEP appealed the Commission's orders to the district court, claiming that the
Commission lacked statutory authority to halt mitigation or to order a refund of over-mitigation
amounts and that it would be entitled to interest on any amount determined to be over-refunded at
its 2004 true-up.  The Cities and the Office of the Public Utility Council (OPC) also appealed,
claiming that the refund of a TDU's over-mitigation properly ought to be paid to the end-use
residential and small commercial consumers, not REPs.  The district court ruled that chapter 39
requires over-mitigation credits to be paid directly to the consumer rather than the REP and affirmed
the Commission's orders regarding all other issues.  AEP now appeals the district court's judgment
resulting from the Commission's stranded cost order.

Discussion
	AEP brings three issues on appeal.  It argues first that the Commission exceeded its
statutory authority in requiring AEP to refund stranded cost amounts that the Commission had
determined, based on the 2001 ECOM calculations, to have been over-recovered.  AEP next argues
that the district court erred in requiring over-mitigation credits to be paid to end-use consumers
rather than to the REPs.  Third, it asserts that the Commission violated chapter 39 in ordering that
AEP would not be entitled to interest on any amount it had over-refunded.  We agree with AEP that
the Commission lacked authority to require a refund of amounts calculated in interim ECOM
estimates to have been over-mitigated.  As explained below, we need not reach AEP's second or
third issues in light of this disposition. (7) 
 Standard of review

	The powers of the Commission include the powers delegated by the legislature in
clear and express statutory language, together with any implied powers that may be necessary to
perform a function or duty delegated by the legislature.  GTE Southwest, Inc. v. Public Util. Comm'n,
10 S.W.3d 7, 12 (Tex. App.--Austin 1999, no pet.).  We may imply that the legislature intended that
an agency would have whatever power would be reasonably necessary to fulfill a function or perform
a duty that the legislature has expressly placed in the agency.  Id.; see also Kawasaki Motors Corp.
U.S.A. v. Texas Motor Vehicle Comm'n, 855 S.W.2d 792, 797 (Tex. App.--Austin 1993, no writ);
Texas Dep't of Human Servs. v. Christian Care Ctrs., Inc., 826 S.W.2d 715, 719 (Tex. App.--Austin
1992, writ denied).  However, even if the legislature intends that an agency created to centralize
expertise in a certain regulatory area "be given a large degree of latitude in the methods it uses to
accomplish its regulatory function," Texas Mun. Power Agency v. Public Util. Comm'n, 150 S.W.3d
579, 586 (Tex. App.--Austin 2004, pet. granted), an agency may not, in the guise of implied powers,
exercise what is effectively a new power, or a power contrary to a statute, on the theory that such
exercise is expedient for the agency's purpose, City of Austin v. Southwestern Bell Tel. Co., 92
S.W.3d 434, 441 (Tex. 2002), nor may it contravene specific statutory language, run counter to the
general objectives of the statute, or impose additional burdens, conditions, or restrictions in excess
of or inconsistent with the relevant statutory provisions.  State v. Public Util. Comm'n, 131 S.W.3d
314, 321 (Tex. App.--Austin 2004, pet. denied).
	To determine the scope of the Commission's powers in this case, we must construe
the relevant provisions of chapter 39 of the utilities code.  Statutory construction is a question of law,
which we review de novo.  In re Forlenza, 140 S.W.3d 373, 376 (Tex. 2004); McIntyre v. Ramirez,
109 S.W.3d 741, 745 (Tex. 2003).  When interpreting a statutory provision, we must ascertain and
effectuate legislative intent.  Tex. Dep't of Protective & Regulatory Servs. v. Mega Child Care, Inc.,
145 S.W.3d 170, 176 (Tex. 2004).  In ascertaining legislative intent, we may consider the evil sought
to be remedied, the legislative history, and the consequences of a particular construction.  See Liberty
Mut. Ins. Co. v. Garrison Contractors, Inc., 966 S.W.2d 482, 484 (Tex. 1998).  Further, we read
every word, phrase, and expression in a statute as if it were deliberately chosen and presume the
words excluded from the statute are done so purposefully.  See Gables Realty Ltd. P'ship v. Travis
Cent. Appraisal Dist., 81 S.W.3d 869, 873 (Tex. App.--Austin 2002, pet. denied); City of Austin
v. Quick, 930 S.W.2d 678, 687 (Tex. App.--Austin 1996) (citing Cameron v. Terrell & Garrett, Inc.,
618 S.W.2d 535, 540 (Tex. 1981)), aff'd, Quick v. City of Austin, 7 S.W.3d 109 (Tex. 1999); see also
2A Norman J. Singer, Sutherland Statutory Construction § 47.25 (6th ed. 2000).  In determining the
scope of the Commission's authority, we must read PURA as a whole to discover the underlying
legislative intent.  State v. Public Util. Comm'n, 883 S.W.2d 190, 196 (Tex. 1994); Texas Building
Owners & Managers Ass'n v. Public Util. Comm'n, 110 S.W.3d 524, 532-33 (Tex. App.--Austin
2003, pet. denied).  We give weight to how the Commission interprets its own powers, but only if
that interpretation is reasonable and not inconsistent with the statute.  Southwestern Bell, 92 S.W.3d
at 441-42; City of Austin v. Hyde Park Baptist Church, 152 S.W.3d 162, 166 (Tex. App.--Austin
2004, no pet.).
 Commission power to order refunds of stranded cost over-recovery
	In AEP's first issue, as in In re TXU, the question is not whether stranded costs may
be over-recovered.  See 67 S.W.3d at 151 (Hecht, J., dissenting).  It is clear that, at least at the 2004
true-up, "[u]tilities that are finally determined to have stranded costs will be entitled to recover only
those costs and no more."  Id.; see also Tex. Util. Code Ann. § 39.262(a).  Rather, the question
presented here is whether the Commission can intervene in a utility's ongoing stranded cost
mitigation before the 2004 true-up and compel refunds based on interim estimates of stranded costs. 
AEP argues that the Commission must wait until it makes its final determination of AEP's stranded
costs in the 2004 true-up proceedings before it can reconcile "actual values" of stranded costs with
its mitigation efforts derived from the 1998 ECOM estimates.  In response, the Commission argues
that the legislature's prohibition on over-recovery of stranded costs--which appears only in the
section governing the 2004 true-up--confers implied authority for it to adjust, limit, or reverse
utilities' mitigation efforts before the 2004 true-up, at which point it would finally reconcile any
over- or under-mitigation as determined in that proceeding.  Our analysis of the text and structure
of the relevant statutes compels us to agree with AEP.
	To effectuate its policy to allow utilities to recover their stranded costs, the legislature
established what the supreme court has described as a "comprehensive scheme" for stranded cost
recovery.  See Tex. Util. Code Ann. § 39.201(b)(2); CenterPoint, 143 S.W.3d at 83.  The legislature
started with data presented in 1998 in the ECOM administrative model to project which utilities
might have stranded costs on December 31, 2001.  Tex. Util. Code Ann. § 39.254.  It then provided
"a number of tools to an electric utility to mitigate stranded costs" between 1999 and the 2004 true-up.  Id.  It mandated that each identified utility use these tools "to reduce the net book value of . . .
its stranded costs each year." Id.  However, it provided no role for the Commission during this phase. 
In 2001, the Commission was to prepare revised stranded cost estimates by entering 2001 data into
the ECOM model and, if necessary, allow the utility to recover stranded costs through the CTC.  Id.
§ 39.201; In re TXU, 67 S.W.3d at 133 (Phillips, C.J., concurring).  In the third and final phase, the
2004 true-up, the Commission is, essentially, to settle up based on a final calculation of each utility's
stranded costs and, as warranted, permit additional stranded cost recovery or, alternatively, require
each utility to refund over-recovered stranded costs. Tex. Util. Code Ann. §§ 39.201(l), .262.
	Only in the 2004 true-up phase, following the final calculation of each utility's
stranded costs, did the legislature explicitly contemplate over-recovery of stranded costs.  See id. 
Likewise, the admonishment that "[a]n electric utility . . . may not be permitted to overrecover
stranded costs," on which the Commission relies, appears solely in the statute governing the 2004
true-up.  See id. §§ 39.201-.262.  In contrast, the legislature did not mention any role for the
Commission at all during the initial mitigation phase.  Id. § 39.254.  As for the second phase, the sole
role the legislature provided for the Commission was to impose the CTC to permit additional
stranded cost recovery as warranted by the 2001 ECOM estimates; the legislature said nothing about
ordering refunds of any over-recovery ascertained through estimates at that juncture.  Id. § 39.201. 
The literal text of these statutes, the comprehensiveness of this stranded cost recover scheme, see
CenterPoint, 143 S.W.3d at 83, and the fact that the prohibition against over-recovery of stranded
costs appears only in the provision governing the 2004 true-up convinces us that the legislature did
not intend to confer power on the Commission to order refunds of stranded cost over-recoveries
based on interim estimates before the 2004 true-up.
	We find further support for our conclusion when we consider the unique nature of
stranded costs and the difficulty of their measurement.  See Tex. Gov't Code Ann. § 311.023 (West
1998) (code construction act).  Conceptually, stranded costs under chapter 39 of the utilities code
exist as of the last day before the opening of retail competition, December 31, 2001.  Tex. Util. Code
Ann. § 39.251(7). (8)  However, accurate calculation of such costs could take years, as a utility may
not know whether it has been able to recover the millions of dollars spent on a generation-related
asset until it sells the last kilowatt generated by that asset.  See In re TXU, 67 S.W.3d at 147 (Brister,
J., concurring) ("it will be impossible to tell whether income stream estimates [on which true-up
stranded cost estimates will be based] are accurate until decades from now when the last kilowatt
is sold."). (9)  Any estimates of stranded costs made before that time--whether in 1998, 2001, or even
in the 2004 true-up--will thus be inherently inaccurate, especially because they depend on myriad,
fluctuating economic variables.  See CenterPoint, 143 S.W.3d at 101 (Brister, J., dissenting); In re
TXU, 67 S.W.3d at 167 (Hecht, J., dissenting).  The dramatic shift in ECOM estimates between 1998
and 2001, caused by unanticipated changes in natural gas prices, demonstrated the volatility of the
estimates.  Accordingly, periodic estimations of stranded costs have been aptly analogized to "a
system in which a jury returns a different verdict every day for a period of years, each one very
different from the verdict the day before, and each one correct."  CenterPoint, 143 S.W.3d at 101
(Brister, J., dissenting).  For the same reasons, revisions "to the ECOM administrative model and
variations in its data input necessarily produce stranded cost estimates that are kaleidoscopic."  In
re TXU, 67 S.W.3d at 163 (Hecht, J., dissenting). 
	Against this backdrop, the legislature mandated that the 2004 true-up calculation
would be the final, controlling calculation of each utility's stranded costs.  In exchange for
sacrificing some accuracy in the calculation of stranded costs, the legislature provided finality
regarding the issue to facilitate the transition to a competitive electricity market by 2008.  See id.;
see also Tex. Util. Code Ann. § 39.262(a); CenterPoint Energy, 143 S.W.3d at 101-02 (Brister, J.,
dissenting); In re TXU, 67 S.W.3d at 147 (Brister, J., concurring). (10)  The statute, then, reflects the
intent of the legislature that only this final calculation, and not the "kaleidoscopic" interim computer
estimates, could serve as the basis for Commission-ordered refunds of stranded cost over-mitigation. 
In re TXU, 67 S.W.3d at 163 (Hecht, J., dissenting).
	The intended role of the interim estimates, in contrast, was solely to provide initial
parameters for rapid stranded cost recovery in the period prior to the 2004 true-up.  This reflects the
legislature's emphasis on such recovery as one of its principal policy objectives in S.B. 7, the fact
that stranded costs were potentially very large, and the desire to finally resolve the issue to the extent
possible by the 2008 advent of full competition.  See Tex. Util. Code Ann. § 39.001(b)(2). 
	We thus reject the Commission's position that the prohibition against over-recovery
of stranded costs in section 39.262(a), the true-up statute, permits it to order refunds each year during
the mitigation phase based on interim ECOM estimates.  It is undisputed that the Commission has
the power to set procedures governing the final stranded cost determinations in 2004 true-ups.  See
id. § 39.262(c).  However, the express authority given in section 39.262, the absence of any language
concerning the power of the Commission before 2004, the express burden placed on the utilities
themselves to effectuate section 39.254, and the fluctuating nature of stranded cost valuation,
together lead us to conclude that the Commission lacks the power to order a refund of any "over-mitigation" that interim computer models suggest has occurred prior to the 2004 true-up.
	To suggest otherwise, the dissent divorces the stranded cost over-recovery prohibition
from its context within the statutory framework and overlooks the role of the final 2004 true-up
calculations in ensuring a clear and certain basis to guide any Commission-ordered refunds of
overrecovered stranded costs.  We agree with the dissent that chapter 39 does not permit utilities the
"windfall" of overrecovered stranded costs, but whether or not such a windfall has actually occurred
is to be determined in the 2004 true-up, not based upon continually shifting, "kaleidoscopic" interim
estimates.  The 2004 true-up calculations, in fact, may belie the earlier estimates of "windfalls" that
the dissent decries.  This is hardly an "ambiguous" statutory scheme, as the dissent urges, much less
an "absurd" one.  Moreover, we should be exceedingly hesitant to apply such labels to justify an
expansion of agency power where, as here, the legislature has squarely rejected requests to explicitly
confer such power on the agency.  In 2001, the legislature was requested to amend chapter 39 to give
the Commission power to reverse stranded cost mitigation efforts prior before the 2004 true-up.  In
the face of many of the same policy considerations that the dissent ably identifies here, the legislature
declined.  Tex. H.B. 2107, 77th Leg., R.S. (2001) (amending Tex. Util. Code § 39.201(d)); see also
In re TXU, 67 S.W.3d 130, 165 (Tex. 2001) (Hecht, J., dissenting).
	We sustain AEP's first issue.  In light of this disposition, we do not reach AEP's
second issue concerning the district court's ordering of excess mitigation refunds directly to
consumers rather than to REPs.  Nor do we reach AEP's third issue concerning the award of interest
on any overpayment AEP is ultimately found to have made in the 2004 true-up. (11)

NEIL MEMBER ACCOUNT BALANCES

	We now turn to the issues presented by the Cities on appeal and begin with their first,
in which they argue that the Commission erred in characterizing AEP's NEIL member account
balance as generation-related rather than as an asset of AEP's transmission and distribution business.

Background
	Nuclear Electric Insurance Limited is a mutual insurance company operated by
utilities, including AEP, which own nuclear power plants.  It issues policies covering property
damage and losses caused by interruptions at nuclear power plants.  NEIL's 79 members own and
control NEIL, have rights to its policyholder dividends, and would share in its assets upon
liquidation.  AEP participates in NEIL directly, as a member in its own right based on its interest in
the twin units of the South Texas Project Nuclear Station (STP), and indirectly, as a member of the
South Texas Project Nuclear Operating Company (Operating Company).  Each year since the STP
entered commercial operation, AEP has paid ratepayer-funded premiums into the insurance fund. 
In other words, AEP has included the cost of these premiums in submitting rates under traditional
ratemaking procedures.  In a typical year, NEIL pays out a portion of its underwriting and investment
income as distributions to member insureds.  The distributions take the form of rebates of the prior
year's premiums.  Distributions are credited to insurance expenses and thus decreased a utility's
reported operating expenses when proposing rates to the Commission under the traditional
ratemaking procedures.
	NEIL also retains an amount of the premiums paid sufficient to cover losses in the
event of two nuclear power accidents.  Although NEIL retains this surplus, it tracks each member's
"share" of it for what NEIL terms "notational" purposes.  An individual member's share is known
as the "Member Account Balance" (MAB).  At the end of 1999, the NEIL surplus stood at $4.1
billion.  AEP's total MAB at the end of 1999 stood at $7.1 million, consisting of $3.1 million
directly held for AEP for its direct NEIL coverage and $4.0 million, its 25.2% share of the Operating
Company's MAB.  Were NEIL to have dissolved at the end of 1999, AEP would have been entitled
to recover that $7.1 million of NEIL's assets.
	When AEP filed its application with the Commission proposing rates based on the
2002 test year, it assigned the generation portion of its NEIL premiums to its affiliated power
generation company.  The Cities contested this allocation, arguing that the MABs should be credited
to transmission and distribution ratepayers (the REPs) rather than to the generating company.  The
Commission referred this question, among others, for a hearing at the State Office of Administrative
Hearings (SOAH).  After a hearing, the Administrative Law Judge (ALJ) concluded that AEP's
MAB is an "asset" towards which ratepayers had contributed in their rates.  As a result, the ALJ
required AEP to calculate its MAB at the end of 2001 (the beginning of deregulation), to establish
that amount as a regulatory asset to remain with AEP, and to moderate rates in future TDU rate
proceedings.  Finally, the ALJ recommended that AEP's MAB be credited to ratepayers as of the
date of deregulation.
	The Commission disagreed and found that NEIL assets are generation-related rather
than transmission-related.  On review, the district court affirmed the Commission's conclusion. 

Discussion
	On appeal, the Cities argue that the Commission erred in determining that AEP's
MAB is generation-related and, thus, attributable to AEP's affiliated generation company.  We
disagree.

 Standard of review
	Our review of this issue is under the substantial-evidence standard.  See Tex. Util.
Code Ann. § 15.001 (West 1998); Reliant Energy, Inc. v. Public Util. Comm'n, 153 S.W.3d 174, 184
(Tex. App.--Austin 2004, no pet.).  We presume that the Commission's findings are supported by
substantial evidence, and the contestant bears the burden of proving otherwise.  See Southwestern
Pub. Serv. v. Public Util. Comm'n, 962 S.W.2d 207, 215 (Tex. App.--Austin 1998, pet. denied). 
We will reverse and remand the cause to the agency when substantial rights of the appellant have
been prejudiced by an agency's findings that are not reasonably supported by substantial evidence
considering the reliable evidence in the record as a whole.  Tex. Gov't Code Ann. § 2001.174(2)(E)
(West 2000).  However, we may not substitute our judgment for that of the agency on the weight of
the evidence.  Southwestern, 962 S.W.2d at 215.  "Substantial evidence" does not mean a large or
considerable amount of evidence but such relevant evidence as a reasonable mind might accept as
adequate to support a conclusion of fact.  Pierce v. Underwood, 487 U.S. 552, 564-65 (1988);
Lauderdale v. Department of Agric., 923 S.W.2d 834, 836 (Tex. App.--Austin 1996, no writ).  We
must first determine whether the evidence as a whole is such that reasonable minds could have
reached the conclusion that the agency must have reached to take the disputed action.  Texas State
Bd. of Dental Exam'rs v. Sizemore, 759 S.W.2d 114, 116 (Tex. 1988); Ramirez v. Texas State Bd.
of Med. Exam'rs, 995 S.W.2d 915, 919 (Tex. App.--Austin 1999, pet. denied).  The test is not
whether the agency made the correct conclusion but whether some reasonable basis exists in the
record for the agency's action.  Railroad Comm'n v. Pend Oreille Oil & Gas Co., 817 S.W.2d 36,
41 (Tex. 1991); Charter Med.-Dallas, Inc., 665 S.W.2d at 452.  The agency may accept or reject in
whole or in part the testimony of the various witnesses who testify.  Central Power & Light Co. v.
Public Util. Comm'n of Tex., 36 S.W.3d 547, 557 (Tex. App.--Austin 2000, pet. denied). We must
uphold an agency's finding even if the evidence actually preponderates against it so long as enough
evidence suggests the agency's determination was within the bounds of reasonableness.
Southwestern, 962 S.W.2d at 215.  If the agency offers more than one ground as the basis for its
decision, we will affirm if we find substantial evidence supporting one ground even if all bases given
would be independently sufficient to support the decision.  Texas State Bd. of Medical Exam'rs v.
Scheffey, 949 S.W.2d 431, 436 (Tex. App.--Austin 1997, writ denied).
 Application
	In this case, the record contains conflicting testimony concerning the proper
characterization of the NEIL MABs.  Nancy Bright, an accountant and a consultant, testified on
behalf of the Cities that the MAB is an "asset" of AEP because it reflects the share of NEIL's funds
to which AEP has a right.  According to her analysis, an REP's rates included amounts to cover
NEIL insurance premiums.  AEP paid those premiums and, as a TDU, received insurance covering
possible losses due to a disruption of service.  NEIL makes distributions out of its surplus every year,
and AEP, as a NEIL member, has a role in determining the amount of the distribution.  Although
NEIL does not classify the amounts in the MABs as "assets" for tax purposes, AEP will be able to
recover the amount in its MAB upon liquidation of NEIL or upon a duly-approved distribution. 
Thus, she concluded AEP's MAB acts as an asset for AEP's transmission and distribution business.
	On the other hand, David Carpenter, AEP's director of Texas regulatory services,
testified that the MABs are more correctly viewed as NEIL's surplus, an equity.  NEIL uses that
surplus to purchase securities, which are NEIL's assets, not the individual utilities.  Historically,
MAB accounting problems had arisen because some NEIL members had been in the process of
selling their ownership rights in their nuclear power plants or were decommissioning their plants. 
Under NEIL bylaws, those utilities would have no longer been members of NEIL and would have
lost any rights associated with their MABs, including the right to receive an MAB distribution upon
NEIL's theoretical dissolution.  However, a utility's MAB interest would not transfer to the new
owner of that nuclear power plant.  Instead, the value of the MAB would be distributed to the
balances of the MABs of the remaining members.  In part to resolve this problem, NEIL established
nonnuclear insurance lines for utilities to purchase so that they might remain NEIL members and
thus maintain their stakes in their MABs.
	Carpenter further testified that MABs represent a surplus, not an asset, because they
result from premium rates paid.  In other words, NEIL charges insurance rates that have been
determined to be "reasonable and prudent" for the purpose of providing insurance for nuclear
accidents.  REPs receive the benefit of the insurance coverage.  In addition, distributions from the
NEIL surplus are made in the form of reduction in rates of premiums, not in the form of money
transfers.
	The Commission made several findings in its order.  First, it determined that NEIL
assets are generation-related and thus remain with the unbundled generation company.  Second, the
Commission found that REP ratepayers have received benefits from the NEIL premiums through risk
reduction and have received credits for rate expenses through NEIL distributions.  Finally, it noted
that "the value of the asset will be determined in the 2004 true-up proceeding at the generation plant
valuation."  Therefore, the Commission concluded that the AEP's NEIL member account balance
be treated as a generation-related asset.
	The Cities' complaints on appeal center on a lack of evidence in the record to support
the Commission's statement about a 2004 true-up reconciliation.  They do not assert a lack of
evidence concerning the Commission's other findings.  The true-up reconciliation ground was only
one of several on which the Commission based its conclusion.  Reasonable minds could differ
concerning the remaining grounds, but the Commission's decision is reasoned.  The assertions that
the MABs are generation-related and that REP ratepayers have benefitted from NEIL insurance and
distributions are supported by substantial evidence in the record.  See Reliant Energy, 153 S.W.3d
at 204.  Substantial evidence exists, then, to support the grounds on which the Commission based
its decision.  As a result, we must affirm under the substantial-evidence rule.  See Scheffey, 949
S.W.2d at 436.  We overrule the Cities' first issue.

DEMAND CHARGES

	In their second issue, the Cities argue that the Commission erred in authorizing
demand charges in excess of those charged under AEP's bundled rate because the Commission
allegedly shifted the burden of proof to the Cities when the burden should have remained on the
utilities and because any demand charges greater than those approved before unbundling negatively
impact competition in violation of section 39.001(d) of the utilities code.

Background
	A demand-metered customer's bill consists of a customer charge, a charge for
delivered electricity, and a charge for "demand."  Demand is a measurement of a customer's actual
demand on the utility's system at a given point in time.  In other words, it is a measurement of the
rate at which energy is consumed.  Demand is physically measured by meters, and most small
commercial and residential users have meters which measure maximum demand over a period of a
month in "per-kilowatt-hour" units.  Large commercial customers often have more expensive meters
that measure maximum demand over short intervals, such as fifteen or thirty minute periods, on a
"per-kilowatt" basis.  The function of the demand charge is to allow the utility to recover fixed costs
arising from the demand placed on the system that are not reflected in the rate set for the electricity
itself.
	Transmission and distribution facilities are "fixed cost" facilities in that they are
constructed to meet local or individual peak demands.  A demand ratchet compensates a utility for
initial cost and maintenance of those facilities over the course of the year, because those costs do not
follow seasonal or other demand patterns.  Use of a ratchet "flattens" these charges throughout the
year.  For example, with an 80% demand ratchet, as ultimately adopted by the Commission, a
customer's demand charge in a given month will be an amount based on the greater of the current
month's demand or 80% of the customer's highest monthly demand in the preceding eleven months. 
	During the initial phase of unbundling, each utility in Texas except for El Paso
Electricity Company had filed a rate case before the Commission.  The Commission decided,
because of the factors common in all the cases, to set the rate cases in the generic docket to be
followed by company-specific hearings.  In the generic docket, the Commission then adopted a rate
design that included a demand charge rather than a rate design based on a "seasonal" differential
system. (12)  It adopted an 80% demand ratchet for transmission and distribution rates because it
decided that an 80% ratchet most appropriately recognized load diversity between different
customers. (13)  The Commission further announced it could grant exceptions to the generic rate
design, (14) but only "if necessary to address extraordinary impacts on the ability of customers to obtain
service from a competitive provider due to restrictions of the price to beat (i.e., 'headroom
concerns'[ (15)])."  Headroom concerns, however, would not automatically mandate an exception to
the generic rate design.
	In AEP's individual docket, AEP had originally proposed a demand charge for large
commercial customers of $2.83/kW, based on their original argument in the generic case that the
demand ratchet be set at 100% rather than at 80%, and supported its proposal with the testimony of
Donald Moncrief, the manager of the regulated pricing and analysis section of one of AEP's
subsidiaries.  The Cities argued instead that the demand charge should remain at the bundled rate
level of $2.74/kW.  They believed that customers "with demands that vary month to month" would
be unlikely to have access to competitive services because the application of the demand ratchet to
demand charges coupled with the proposed rate would reduce headroom to non-competitive levels. 
AEP responded that the Cities failed to justify that a headroom problem existed or the necessity of
a shift.  The ALJ found that AEP produced evidence that the proposed rate would not create a
headroom problem.  She also found that the Cities failed to produce any specific evidence of "an
extraordinary headroom concern that warrants an exception to the generic rate design."  Thus, she
concluded that reducing AEP's demand charge to the bundled rate level would arbitrarily shift costs
to "high-load-factor customers."  She made no conclusion about the proper demand charge rate.  The
Commission agreed with the ALJ's analysis and ultimately set AEP's demand charge at $3.27/kW. 

Discussion
	The Cities bring two challenges to the Commission's order concerning AEP's demand
charge for large commercial customers. (16)  First, the Cities claim that the burden of proof for showing
that a proposed rate is "just and reasonable" lies with the utility.  See Tex. Util. Code Ann. § 36.006
(West 1998).  As a result, they argue that the Commission erred in adopting the ALJ's analysis. 
Next, the Cities argue that the Commission's adoption of "demand charges exceeding those assessed
for bundled service negatively impacts competition in violation of" utilities code section 39.001(d). (17) 
The Cities do not argue that the adopted rate negatively impacts competition.  Rather, they argue that
any rate greater than the bundled rate negatively impacts competition in violation of section
39.001(d).  Nor do the Cities argue that the Commission acted outside its statutory authority in
setting the demand charge.  They argue only that the rate itself violates the statutory requirements. 
Assuming without deciding that the burden in this case properly lay with AEP, (18) the essence of both
challenges to the demand charge set by the Commission is that the evidence produced by AEP and
relied upon by the Commission does not support the Commission's decision to set a rate greater than
the bundled rate.  Thus, as when we considered the proper characterization of the NEIL MABs,
above, in considering the Cities' second issue we will apply the substantial-evidence test.
	AEP initially proposed its demand charge for large commercial customers and offered
Moncrief's testimony to support the proposition that its demand charge would leave sufficient
headroom for competition and would provide an attractive rate for customers.  Because AEP is
entitled to recover its transmission and utility costs, any reduction in the demand charge for large
commercial customers would result in an increase in rates, and a related decrease in headroom (and
thus possible decrease in competition), for other customer classes.  Large commercial customers,
such as the Cities, place the largest share of demand on the system.  As a result, Moncrief analyzed
"typical customer bills" based on AEP's set of proposed rates and concluded that the proposed
demand charge for large commercial customers would result in bills that would adequately reflect
their share of the demand placed on the system.
	In response, the Cities offered the testimony of Steven Anderson, a consultant
specializing in regulatory analysis and asset valuation, to argue that the Commission should set
AEP's demand charge at the level of its unbundled demand charge.  He testified that a higher
demand charge coupled with an 80% demand ratchet would create a financial hardship on REPs that
elect "to serve customers with demands that vary significantly from month to month.  As a result,
it is unlikely such a customer will have access to competitive service."  He then suggested that the
revenue shortfall that would result from lower demand charges be recovered by increasing energy
charges.  Moncrief responded to Anderson's testimony by pointing out that Anderson's
recommendation would result in higher rates for residential and small commercial customers to
support lower demand charges for large commercial customers.  This cost-burden shifting, he
argued, would violate "the rule that rates should be based on costs" and would reduce headroom for
residential and small commercial customers.
	Considering this testimony, the ALJ found that Moncrief produced analysis
establishing that the proposed demand charge would produce no headroom problem for typical
customers.  She also accepted AEP's argument that the Cities' position would shift the burden
created by the demand ratchet away from high demand, large commercial customers onto residential
and small commercial customers.  The Commission agreed with the ALJ's conclusions.
	We find that reasonable minds could have reached the conclusion that the
Commission did.  AEP produced evidence in its case to support its proposed rate and rebutted the
Cities' proffered evidence.  The Commission could have accepted in whole Moncrief's testimony,
which supported setting a demand charge greater than the bundled rate, and rejected in whole
Anderson's testimony.  Therefore, we find that the Commission based on substantial evidence its
decision to set a demand charge greater than the demand charge approved for the bundled utility. 
We overrule the Cities' second issue.

CONCLUSION

	We have sustained AEP's arguments that the Commission lacked authority to order
refunds of allegedly "over-mitigated" stranded costs before a final determination is made at the 2004
true-up.  As a result, we reverse the portion of the district court's judgment concerning stranded cost
over-mitigation and remand those issues for further proceedings consistent with this opinion.  At the
same time, we have overruled the Cities' issues concerning the proper characterization of AEP's
NEIL member account balances and the adoption of demand charges greater than the demand
charges approved for the bundled utility.  Thus, we affirm the district court's judgment in those
respects.


					__________________________________________

					Bob Pemberton, Justice

Before Justices B. A. Smith, Patterson and Pemberton:  Opinion by Justice Pemberton;
	Dissenting Opinion by Justice B. A. Smith

Affirmed in Part; Reversed and Remanded in Part

Filed:   September 23, 2005
1.   The cities participating in this appeal are municipalities served by AEP Texas Central
Company, the transmission and distribution utility formerly owned by Central Power and Light
Company, and include Alice, Aransas Pass, Beeville, Camp Wood, Carrizo Springs, Charlotte,
Corpus Christi, Cotulla, Dilley, Eagle Pass, Edinburg, Edna, Ganado, George West, Gregory,
Harlingen, Ingleside, Karnes City, Kingsville, La Feria, Laredo, Leakey, Los Fresnos, Lyford, Lytle,
Mathis, McAllen, Mercedes, Odem, Orange Grove, Pearsall, Pleasanton, Port Aransas, Port Isabel,
Port Lavaca, Rancho Viejo, Raymondville, Refugio, Rio Hondo, Rockport, Roma, San Benito, San
Juan, Sinton, Smiley, Taft, and Victoria.  The City of Corpus Christi has served as the "lead" city
in this litigation.  We will refer to these municipalities collectively as "the Cities."
2.   As explained in CenterPoint,

The Legislature recognized that in fundamentally changing the industry, it was
altering the assumptions that had led utilities to invest large sums in power
generation assets.  The Legislature understood that the cost of these assets likely
would be recovered in a regulated environment, but might well become
uneconomic and thus unrecoverable in a competitive, deregulated electric power
market.  The Legislature called such uneconomic assets stranded costs.  The term
"stranded costs" . . . [means] the extent to which the book value of
generation-related assets and purchased power contracts exceeds their market
value. 

	The Legislature concluded that if generating plants became uneconomic as
a result of legislatively mandated deregulation, it was in the public interest for
utilities to be made whole by recovering their full investment in those generation
plants, although the utilities would no longer receive a return on those
investments.  The Legislature determined that utilities should not be required to
forfeit their investments in generating plants with the advent of deregulation. 

CenterPoint Energy, Inc. v. Public Util. Comm'n of Tex., 143 S.W.3d 81, 82-83 (Tex. 2004)
(footnotes omitted).
3.   "Small commercial customers" are commercial customers having a peak demand of 1,000
kilowatts or less.  Tex. Util. Code Ann. § 39.202(o) (West Supp. 2004-05).
4.   "Securitization" is a method to recover stranded costs by which a utility issues transition
bonds that are secured by, or payable from, a nonbypassable transition charge, assessed for the use
or availability of electric service, as approved in a Commission-issued financing order.
5.   In part, the difference between the 1998 and 2001 estimates could be related to an
unprojected surge in natural gas prices between those years, which affected the market price of
nuclear generating plants relative to those powered by natural gas.  See In re TXU Elec. Co., 67
S.W.3d 130, 133 (Tex. 2001) (Phillips, C.J., concurring).
6.   At that time, TXU Electric Co. filed a petition for writ of mandamus in the supreme court,
arguing that the Commission lacked jurisdiction to order reverse mitigation credits based on the 2001
interim estimates.  See In re TXU Elec. Co., 67 S.W.3d 130, 131 (Tex. 2001) (per curiam).  Six
members of the court voted to deny relief for different reasons.  Id.  Chief Justice Phillips, joined by
two others, would not have exercised mandamus jurisdiction because he believed TXU had an
adequate remedy at law.  Id. at 132-36 (Phillips, C.J., concurring).  Justice Baker and Justice
Rodriguez felt that the court had no jurisdiction to mandamus a state board or commission.  Id. at
136-45 (Baker, J., concurring).  Justice Brister, at the time serving on the court of appeals and sitting
by assignment, believed that the court did have jurisdiction but that the Commission had power to
order reverse mitigation efforts.  Id. at 145-50 (Brister, J., concurring).  Justice Hecht, joined by
then-associate Justice Jefferson and Justice Owen, argued that the court had jurisdiction and that the
Commission lacked statutory authority to order reverse mitigation efforts.  Id. at 150-71.

	In In re TXU, only four justices reached the issues we confront here regarding the
Commission's power to order reverse mitigation based on interim stranded cost estimates.  Although
thus not binding authority, strictly speaking, these opinions provide especially helpful background
regarding the applicable statutes, the nature of stranded costs, and the parameters of the debate
regarding Commission power to order reverse mitigation efforts.  For these purposes, we cite these
opinions extensively in the foregoing discussion.
7.   For the same reasons, we will not separately address the three issues presented by cross-appellant Constellation New Energy, an unaffiliated REP.  Constellation joins AEP in arguing that
the district court erred in requiring over-mitigation credits to be paid to end-use consumers rather
than to the REPs.  It also argued that applying over-mitigation credits to REPs does not discriminate
against residential and small commercial customers and does not permit TDUs to over-recover
stranded costs, thus joining AEP's second issue.  
8.   Thus, the differing stranded cost estimates in 1998 and 2001 (and possibly in the 2004 true-up) are not snapshot views of continually accruing costs at different points in time, but different
estimates of the same figure. 
9.   We note that, were the issue of over-recovery of stranded costs directly addressed in In re
TXU, Justice Brister would have held that the Commission has authority to address "over-recovery"
of stranded costs before the 2004 true-ups.  See 67 S.W.3d at 145-50.  We cite his opinion here for
its helpful discussion of the nature of stranded costs and the problems associated with their recovery.
10.   As Justice Brister noted in In re TXU, that the 2004 valuations will be final does not mean
that they will be accurate.  The legislature guarantees only finality in this phase of the transition to
competition, not the ultimate accuracy of the stranded cost valuations.
11.   We assume that the Commission will consider on remand of this case the implications of
CenterPoint Energy, Inc. v. Public Util. Comm'n of Tex., 143 S.W.3d 81 (Tex. 2004).
12.   Under a "seasonal" differential charge system, a utility would be permitted to charge a
higher rate during summer months (typically from June through September) and a lower rate during
the rest of the year to reflect the demand put on the system during the peak demand summer months. 
A seasonal differential system is also termed a "flat kWh" charge.  To further confuse matters, a
demand charge system may also be termed a "seasonal kWh charge."  Typically, a demand charge
system results in charges that remain relatively "flat" over the course of a year.  A seasonal
differential charge system, on the other hand, yields higher charges during the summer and lower
charges the rest of the year.  Generated revenue for TDUs is generally the same from either system. 
The differences lie mostly in the flow of the revenue stream.
13.   In doing so, it rejected AEP's proposed 100% demand ratchet.  
14.   The Commission exempted seasonal agricultural customers from the demand ratchet on
finding that those customers only use electricity in significant amounts one or two months a year. 
Thus, seasonal agricultural customers are only billed demand charges during months of significant
demand.
15.   "Headroom" refers to the margin between the "price to beat" and the new REPs' costs of
providing electricity.  From January 1, 2002 until January 1, 2007, electric providers formerly
affiliated with regulated utilities must provide electricity at rates that are six percent lower than their
rates before deregulation.  This rate is known as the "price to beat."  See Tex. Util. Code Ann.
§ 39.202 (West Supp. 2004-05).  In enacting the price-to-beat statute, the legislature intended to
create incentives for new REPs not affiliated with the regulated utility industry to enter the market
and compete for customers with affiliated REPs, those that were formerly part of the bundled utility
companies.  Thus, the greater the headroom, the more room for new market entrants to engage in
pure competition with affiliated REPs.
16.   Neither party argues about the evidence supporting the rate ultimately adopted by the
Commission, $3.27/kW.  They argue only about the Commission's adoption of any rate greater than
the bundled rate.
17.   The Commission "shall authorize or order competitive rather than regulatory methods to
achieve the goals of [chapter 39 of the utilities code] to the greatest extent feasible and shall adopt
rules and issue orders that are both practical and limited so as to impose the least impact on
competition."  Tex. Util. Code Ann. § 39.001(d) (West Supp. 2004-05).  This statutory mandate does
not forbid the Commission from setting rates greater than the unbundled rate.  It only requires that
orders "impose the least impact on competition."  Id.
18.   See Office of Pub. Util. Counsel v. Public Util. Comm'n of Tex., No. 03-03-00462-CV, 
slip op., at *17-18 (Tex. App.--Austin July 28, 2005, no pet. h.) (claim that Commission improperly
shifted burden of proof in fuel-factor case, when utility offered evidence in support of its position,
decided under substantial-evidence review).
