aep-texas-central-company-the-state-of-texas-by-and-through-the-office-of ( 2008 )

TEXAS COURT OF APPEALS, THIRD DISTRICT, AT AUSTIN
NO. 03-07-00196-CV
Appellants, AEP Texas Central Company; the State of Texas,
by and through the Office of the Attorney General, Consumer Protection
and Public Health Division, Public Agency Representation Section; et al.
// Cross-Appellant, Public Utility Commission of Texas
v.
Appellee, Public Utility Commission of Texas// Cross-Appellees, AEP Texas
Central Company; the State of Texas, by and through the Office of the
Attorney General, Consumer Protection and Public Health Division,
Public Agency Representation Section; et al.
FROM THE DISTRICT COURT OF TRAVIS COUNTY, 250TH JUDICIAL DISTRICT
NO. D-1-GV-06-000827, HONORABLE JOHN K. DIETZ, JUDGE PRESIDING
CONCURRING AND DISSENTING OPINION
The Public Utility Commission issued a final order in the true-up proceeding to
finalize “stranded costs” and other true-up balances for the AEP Texas Central Company and CPL
Retail Energy, L.P. (collectively “TCC”). The district court affirmed the Commission’s final order
in most respects, but reversed on three issues. For the reasons discussed below, I would affirm the
district court’s judgment in part, reverse in part, and remand this cause to the Commission for further
proceedings.
I. Factual and Procedural Background
In 1999, the legislature determined it was in the public interest to restructure and
partially deregulate the Texas retail electric power industry. See generally Tex. Util. Code Ann.
§ 39.001 (West 2007). To accomplish this mandate, the legislature enacted Senate Bill 7 (“SB 7”),
which amended the Public Utility Regulatory Act (“PURA”).1 See Act of May 27, 1999, 76th Leg.,
R.S., ch. 405, 1999 Tex. Gen. Laws 2543 (now codified in Chapter 39 of the PURA, Tex. Util.
Code Ann. §§ 39.001-.910 (West 2007)); see also CenterPoint Energy Houston Electric, LLC
v. Gulf Coast Coalition of Cities, No. 03-05-00557-CV, 2008 Tex. App. LEXIS 2819, at *3-19
(Tex. App.—Austin Apr. 17, 2008, no pet. h.) (op. on reh’g) (describing statutory framework
for transition to competitive retail electric market) (hereafter “CenterPoint”). SB 7 required each
integrated electric utility to separate its business activities into three separate units—a power
generation company, a transmission and distribution utility, and a retail electric provider. See
Tex. Util. Code Ann. § 39.051 (West 2007).
As part of the transition from regulation to retail competition, the legislature
authorized each electric utility to recover “all of its net, verifiable, nonmitigable stranded costs
incurred in purchasing power and providing electric generation service.” Tex. Util. Code Ann.
§ 39.252(a) (West 2007). The term “stranded costs” is defined in section 39.251 of the PURA,2 but
1
Tex. Util. Code Ann. §§ 11.001-64.158 (West 2007).
2
Section 39.251(7) defines the term “stranded costs” as:
the positive excess of the net book value of generation assets over the market value
of the assets, taking into account all of the electric utility’s generation assets, any
above market purchased power costs, and any deferred debit related to a utility’s
discontinuance of the application of Statement of Financial Accounting Standards
2
generally speaking, stranded costs represent prudently incurred expenditures made by the utilities
in a regulated environment—previously recoverable over time through regulated rates paid by
consumers—that have become unrecoverable in a competitive market. See Reliant Energy, Inc.
v. Public Util. Comm’n, 101 S.W.3d 129, 132 (Tex. App.—Austin 2003) (hereafter “Reliant I”),
rev’d in part sub nom. CenterPoint Energy, Inc. v. Public Util. Comm’n, 143 S.W.3d 81 (Tex. 2004)
(op. on reh’g). Recovery of stranded costs is one of the final steps in the transition from traditional
cost-of-service regulation to retail competition.
In addition to the recovery of stranded costs, the legislature’s deregulation plan
required the Commission to determine each electric utility’s final fuel balance and capacity auction
true-up award. See Tex. Util. Code Ann. §§ 39.201, .202(c), .262(d) (West 2007). Once determined
by the Commission, the net sum of the final fuel balance and the capacity auction true-up award
would result in a credit or bill from the affiliated power generation company to the transmission and
distribution utility. See id. § 39.262(d).
To recover its stranded costs and finalize its other true-up balances, TCC filed an
application with the Commission seeking a total true-up balance of $2,406,271,176, including
interest through September 2005. This amount included a requested capacity auction true-up award
No. 71 (“Accounting for the Effects of Certain Types of Regulation”) for
generation-related assets if required by the provisions of this chapter. For purposes
of Section 39.262, book value shall be established as of December 31, 2001, or the
date a market value is established through a market valuation method under Section
39.262(h), whichever is earlier, and shall include stranded costs incurred under
Section 39.263.
Tex. Util. Code Ann. § 39.251(7) (West 2007).
3
of $482,664,890, less TCC’s final fuel balance of $176,698,379. Several consumer groups
intervened in the proceedings before the Commission to challenge TCC’s requested recovery.
Among the intervenors were the State of Texas, the Office of Public Utility Counsel (OPC), the
Texas Industrial Energy Consumers (TIEC), the Cities served by TCC (Cities),3 the Alliance for
Valley Healthcare (AVH), the Alliance for Retail Markets, the Brownsville Public Utility Board, the
Commercial Customers Group (CCG), Occidental Power Marketing, Reliant Energy, Inc., and the
Texas Cotton Ginners’ Association. On review of TCC’s application, the Commission made several
adjustments to the amounts requested by TCC. These adjustments related to TCC’s failure to use
commercially reasonable means to mitigate potential stranded costs in relation to the sale of TCC’s
share of the South Texas Nuclear Project (STP), the bundling of certain TCC gas plants as part of
the sale of the Coleto Creek Coal Plant, disallowances to TCC’s capacity auction true-up award, and
other items. In sum, the Commission awarded TCC a total recovery of $1,475,933,779.
TCC and six intervenors sought judicial review of the Commission’s final order in
district court. See Tex. Util. Code Ann. §§ 15.001, 39.262(j) (West 2007); Tex. Gov’t Code Ann.
§§ 2001.171, .176 (West 2000). The district court reversed the Commission’s order on three issues.
The district court held that the Commission erred by making adjustments to the net book value of
3
The 63 participating cities included: Aransas Pass, Beeville, Charlotte, Devine, Dilley,
Eagle Pass, Edinburg, Edna, Ganado, Indian Lake, Ingleside, Ingleside on the Bay, Jourdanton,
Kingsville, Los Fresnos, Luling, Lyford, Lytle, McAllen, Mathis, Mercedes, Nordheim, Odem,
Palmview, Portland, Port Lavaca, Poteet, Primera, Raymondville, Rio Hondo, Sabinal, Smiley,
South Padre Island, Victoria, Alamo, Bishop, Goliad, Gregory, Harlingen, La Feria, Pharr,
Pleasanton, Port Aransas, Rancho Viejo, Weslaco, Carizzo Springs, Del Rio, Donna, Laredo, Crystal
City, Corpus Christi, San Benito, Uvalde, Bay City, Bayview, Camp Wood, George West, Palm
Valley, Refugio, Rio Grande City, San Juan, Sinton, and Taft.
4
TCC’s generation assets, by excluding the testimony and report offered by an expert witness, and
by applying an interest rate specified in a rule that the supreme court had previously invalidated.
TCC and six of the intervenors4 have filed separate appeals challenging the district court’s judgment,
and the Commission has filed a cross-appeal.
II. Discussion
On appeal, the parties urge this Court to reverse the district court’s judgment on
various grounds. The Commission urges us to reverse those portions of the district court’s judgment
which reversed the Commission’s final order. Specifically, the Commission urges that the district
court erred in its findings that the Commission was prohibited from making adjustments to the net
book value of TCC’s generation assets, that the interest rate used by the Commission was invalid,
and that the Commission erred in excluding the testimony and report of an expert witness. TCC
urges us to reverse portions of the district court’s judgment on the grounds that the district court
erred in upholding the Commission’s disallowance and reduction to TCC’s capacity auction true-up
award, and in affirming the Commission’s treatment of Accumulated Deferred Investment Tax
Credits, Excess Deferred Federal Income Taxes, and excess mitigation credits. In addition, like the
Commission, TCC urges that the district court erred in reversing the Commission’s use of the
interest rate specified in the Commission’s true-up rule.
4
Those intervenors participating in this appeal include the State of Texas, Cities, AVH,
CCG, OPC, and TIEC. The State, Cities, AVH, and TIEC have filed joint briefs, and I refer to them
collectively as the “Joint Intervenors.” OPC and CCG have also filed joint briefs, and I refer to them
collectively as “OPC/CCG.”
5
The six intervenors likewise assert various challenges to the district court’s judgment.
The Joint Intervenors argue that the district court erred in reversing the Commission’s adjustments
to the net book value of TCC’s generation assets and in reversing the Commission’s exclusion of
the testimony and report of an expert witness. The Joint Intervenors further argue that the district
court erred in affirming the Commission’s adjustments to the net book value of the STP and the
Coleto Creek Coal Plant, as well as the Commission’s inclusion of construction work in progress
(CWIP) in its calculation of net book value. The Joint Intervenors also argue that the district court
erred in affirming the Commission’s failure to use the ECOM, or excess-cost-over-market, method
to value TCC’s nuclear generation assets and in affirming the Commission’s determination that
TCC’s auction of its share of the STP met statutory requirements. Finally, the Joint Intervenors
argue that the Commission erred in allowing TCC to recover excess mitigation credits paid to retail
electric providers, allowing TCC to recover interest on its capacity auction true-up award, and by
refusing to reduce stranded costs to account for certain profits achieved by TCC from the sale of its
generation assets.
In addition to the claims raised by the Joint Intervenors, OPC/CCG also raise three
challenges to the district court’s judgment affirming the Commission’s final order. First, OPC/CCG
argue that the Commission violated the PURA by allowing TCC to recover stranded costs for
generation assets that were not “uneconomic.” Like the Joint Intervenors, OPC/CCG also allege that
the Commission erred in its failure to use the ECOM method to value TCC’s nuclear generation
assets. Finally, OPC argues that the Commission erred in failing to reduce TCC’s stranded cost
recovery by the total amount of TCC’s excess earnings for 1999-2001.
6
A. Standard of Review
This Court reviews the Commission’s final order under the substantial evidence rule.
See Tex. Util. Code Ann. § 15.001; Tex. Gov’t Code Ann. § 2001.174 (West 2000). Under
the substantial evidence rule, we give significant deference to the agency in its field of expertise.
Railroad Comm’n v. Torch Operating Co., 912 S.W.2d 790, 792 (Tex. 1995); Texas Health
Facilities Comm’n v. Charter Medical-Dallas, Inc., 665 S.W.2d 446, 452 (Tex. 1984). We presume
that the agency’s order is valid and that its findings, inferences, conclusions, and decisions are
supported by substantial evidence. City of El Paso v. Public Util. Comm’n, 883 S.W.2d 179,
185 (Tex. 1994); Charter Medical, 665 S.W.2d at 452. The complaining party has the burden to
overcome this presumption. City of El Paso, 883 S.W.2d at 185; Hammack v. Public Util. Comm’n,
131 S.W.3d 713, 725 (Tex. App.—Austin 2004, pet. denied). In conducting a substantial evidence
review, we evaluate the entire record to determine whether the evidence as a whole is such that
reasonable minds could have reached the conclusion the agency must have reached in order to
take the disputed action. Texas State Bd. of Dental Exam’rs v. Sizemore, 759 S.W.2d 114, 116
(Tex. 1988); Suburban Util. Corp. v. Public Util. Comm’n, 652 S.W.2d 358, 364 (Tex. 1983). We
may not substitute our judgment for that of the agency on the weight of the evidence on questions
committed to the agency’s discretion. Tex. Gov’t Code Ann. § 2001.174; Charter Medical,
665 S.W.2d at 452; H.G. Sledge, Inc. v. Prospective Inv. & Trading Co., Ltd., 36 S.W.3d 597, 602
(Tex. App.—Austin 2000, pet. denied).
Under a substantial evidence review, the issue for the reviewing court is not whether
we believe the agency’s decision was correct, but whether the record demonstrates some reasonable
7
basis for the agency’s action. Charter Medical, 665 S.W.2d at 452; Central Power & Light Co.
v. Public Util. Comm’n, 36 S.W.3d 547, 561 (Tex. App.—Austin 2000, pet. denied). The evidence
in the record may preponderate against the decision of the agency and nevertheless amount to
substantial evidence. Charter Medical, 665 S.W.2d at 452; Meier Infinity v. Motor Vehicle Bd.,
918 S.W.2d 95, 98 (Tex. App.—Austin 1996, writ denied). We will sustain the agency’s order if the
evidence is such that reasonable minds could have reached the conclusion that the agency must have
reached in order to justify its action. Charter Medical, 665 S.W.2d at 453; Suburban Util. Corp.,
652 S.W.2d at 364. We must uphold the agency’s order unless the agency’s decision is not
reasonably supported by substantial evidence, in violation of a constitutional or statutory provision,
in excess of the agency’s statutory authority, made through unlawful procedure, affected by other
error of law, arbitrary or capricious, or characterized by an abuse of discretion. See Tex. Gov’t Code
Ann. § 2001.174(2)(A)-(F).
Several issues raised by the parties involve questions of statutory construction, which
we review de novo. See, e.g., City of San Antonio v. City of Boerne, 111 S.W.3d 22, 25 (Tex. 2003)
(appellate courts review matters of statutory construction de novo); In re Humphreys, 880 S.W.2d
402, 404 (Tex. 1994) (questions of law are always subject to de novo review). When construing
a statute, our primary goal is to determine and give effect to the legislature’s intent. City of
San Antonio, 111 S.W.3d at 25. To determine legislative intent, we look to the statute as a whole,
as opposed to isolated provisions. State v. Gonzalez, 82 S.W.3d 322, 327 (Tex. 2002). We begin
with the plain language of the statute at issue and apply its common meaning. City of San Antonio,
111 S.W.3d at 25. Where the statutory text is unambiguous, we adopt a construction supported
8
by the statute’s plain language, unless that construction would lead to an absurd result. Fleming
Foods of Tex., Inc. v. Rylander, 6 S.W.3d 278, 284 (Tex. 1999). We give serious consideration to
an agency’s interpretation of the statutes it is charged with enforcing, so long as that interpretation
is reasonable and consistent with the statutory language. Tarrant Appraisal Dist. v. Moore,
845 S.W.2d 820, 823 (Tex. 1993); Steering Comms. for the Cities Served by TXU Elec. v. PUC,
42 S.W.3d 296, 300 (Tex. App.—Austin 2001, no pet.). This is particularly true when the statute
involves a complex subject matter. Steering Comms. for Cities, 42 S.W.3d at 300. Courts, however,
“do not defer to administrative interpretation in regard to questions which do not lie within
administrative expertise, or deal with a nontechnical question of law.” Rylander v. Fisher Controls
Int’l, Inc., 45 S.W.3d 291, 302 (Tex. App.—Austin 2001, no pet.).
Additionally, several issues raised by the parties challenge the Commission’s
authority. The Public Utility Commission “is a creature of the Legislature and has no inherent
authority.” Public Util. Comm’n v. GTE-SW Corp., 901 S.W.2d 401, 407 (Tex. 1995). Like other
state administrative agencies, the Commission “has only those powers that the Legislature expressly
confers upon it” and “any implied powers that are necessary to carry out the express responsibilities
given to it by the Legislature.” Public Util. Comm’n v. City Pub. Serv. Bd., 53 S.W.3d 310, 316
(Tex. 2001). It is not enough that the power claimed by the Commission be reasonably useful to
the Commission in discharging its duties; the power must be either expressly conferred or necessarily
implied by statute. The agency may not “exercise what is effectively a new power, or a power
contradictory to the statute, on the theory that such a power is expedient for administrative
purposes.” Id.
9
B. The Statutory Scheme
Before addressing the issues raised by the parties, it is helpful to review the statutory
scheme allowing for the recovery of stranded costs and other true-up balances.
1. Recovery of stranded costs
When the legislature mandated the transition from traditional cost-of-service
regulation to retail competition, it recognized that many utility companies had made very large
investments to build power generation plants, and that while the costs of these power plants might
be recoverable from ratepayers in a regulated environment, these same costs “might well become
uneconomic and thus unrecoverable in a competitive, deregulated power market.” CenterPoint
Energy, 143 S.W.3d at 82; see also City of Corpus Christi v. Public Util. Comm’n, 51 S.W.3d 231,
237-38 (Tex. 2001). The legislature called these uneconomic assets “stranded costs.” CenterPoint
Energy, 143 S.W.3d at 82; see also Tex. Util. Code Ann. §§ 39.001(b)(2), .251(7) (West 2007). As
part of the transition to retail competition, the legislature made an express finding that it was in the
public interest to allow utility companies to recover their stranded costs. See Tex. Util. Code Ann.
§ 39.001(b)(2) (West 2007). The legislature thus “set forth a comprehensive scheme for estimating,
finalizing, and recovering those costs.” CenterPoint Energy, 143 S.W.3d at 83; see Tex. Util. Code
Ann. §§ 39.201, .251-.254, .256-.265, .301-.313 (West 2007).
The legislature provided a mechanism in section 39.262 of the PURA for each utility
to recover its stranded costs. See Tex. Util. Code Ann. § 39.262. This mechanism requires each
transmission and distribution utility, its affiliated retail electric provider, and its affiliated power
generation company to jointly file an application with the Commission to finalize stranded costs.
10
Id. § 39.262(c). The legislature provided a formula to calculate a utility’s stranded costs. Id.
§ 39.251(7). Under this formula, a utility’s stranded costs equal the excess amount of the net book
value of generation assets minus the market value of those assets—i.e., SC = NBV – MV. Id.
Each utility has the burden of quantifying its stranded costs using one of four statutory
methods. Id. § 39.262(h). These methods include sale-of-assets, stock valuation, partial stock
valuation, or exchange of assets. Id. § 39.262(h)(1)-(4). TCC chose to establish its stranded costs
using the sale-of-assets method. Under this method, TCC was required to demonstrate that it sold
its generating assets in a “bona fide third-party transaction under a competitive offering.” Id.
§ 39.262(h)(1). Once this showing has been made, the total net value realized from the sale will
establish the market value of the generation assets sold. Id.
The legislature recognized, however, that during the transition from regulation to
retail competition, utilities would not necessarily have a business incentive to reduce their potential
stranded costs. Accordingly, the legislature provided a statutory incentive—the legislature required
each utility to “pursue commercially reasonable means to reduce its potential stranded costs,
including good faith attempts to renegotiate above-cost fuel and purchased power contracts or
the exercise of normal business practices to protect the value of its assets.” Id. § 39.252(d). The
legislature also required the Commission to consider each utility’s efforts to mitigate potential
stranded costs when determining the utility’s final stranded cost balance. Id. In addition, the
legislature required the Commission to ensure that each utility does not overrecover stranded costs.
Id. § 39.262(a); see also CenterPoint Energy, 143 S.W.3d at 98-99.
11
2. Determination of non-stranded-cost true-ups
As part of the transition to deregulation, the legislature also required the Commission
to conduct additional true-up proceedings to calculate each utility’s final fuel balance and capacity
auction true-up award. Tex. Util. Code Ann. § 39.262(d). The parties do not dispute the
Commission’s determination of TCC’s final fuel balance, but TCC and the Joint Intervenors both
challenge the Commission’s determination of TCC’s capacity auction true-up award. Following is
a brief description of the purpose of the capacity auction and its statutory requirements.
To ensure the availability of power in the emerging competitive market, the
legislature required power generation companies to auction entitlements to at least 15% of their
installed generation capacity beginning 60 days prior to the start of customer choice on January 1,
2002. See Tex. Util. Code Ann. §§ 39.153, .156 (West 2007); Reliant I, 101 S.W.3d at 137. The
utilities’ obligation to auction generation capacity continued until the earlier of 60 months
(five years) after January 1, 2002, or the date on which the Commission determines that 40 percent
or more of the electric power consumed by residential and small commercial customers within the
affiliated transmission and distribution company’s service area before the onset of customer choice
is provided by nonaffiliated retail electric providers. See Tex. Util. Code Ann. § 39.153(b). The
legislature directed the Commission to adopt rules defining the scope of the capacity entitlements
to be auctioned and the procedure for the auction of those entitlements. Id. § 39.153(e)-(g); see also
16 Tex. Admin. Code § 25.381 (West 2007) (PUC Capacity Auction Rule).5
5
The current version of the capacity auction rule differs from that version originally
promulgated by the Commission. Compare 25 Tex. Reg. 9139 (2000) (original rule), adopted
25 Tex. Reg. 12961 (effective Jan. 4, 2001), with 16 Tex. Admin. Code § 25.381 (2007) (current
12
The legislature was concerned that consumers and generation companies could be
harmed by “distortions and fluctuations in the market price of power during the first two years of
deregulation.” See CenterPoint Energy, 143 S.W.3d at 96. To alleviate this concern, the legislature
designed the capacity auction true-up proceeding. Id. The purpose of the capacity auction true-up
proceeding was to provide those companies forced to participate in the required capacity auctions
with a guaranteed return on the sales of power, while at the same time ensuring that consumers
would not be harmed by fluctuating prices and market instability. Id. The “guaranteed return,” or
capacity auction true-up award, represents the difference between the price of power projected by
the Commission in the 2001 ECOM model6 and the price of power obtained through the auctions.
See Tex. Util. Code Ann. § 39.262(d)(2). The Commission was charged with calculating this return
in the capacity auction true-up proceeding. Id. § 39.262(d). As a result of the capacity auction true-
up proceeding, consumers and generation companies were guaranteed that generation companies
“will receive no more and no less” than a set margin for power sales predetermined by the
Commission in 2001 when the ECOM model was run in compliance with section 39.201.
CenterPoint Energy, 143 S.W.3d at 96.
rule). The primary difference relevant to this appeal concerns the adoption of “safe harbors” for the
purpose of compliance with the rule. As originally adopted, the capacity auction rule did not include
a safe harbor—or alternate means of compliance—but the rule was amended in 2002 to add a
safe harbor. See 27 Tex. Reg. 5982 (2002) (adding subsection 25.381(h)(1)(B)(iv) among other
provisions). I cite the current rule unless noted otherwise.
6
The ECOM model is a computer model used by the Commission to predict whether a
utility will incur stranded costs. See CenterPoint Energy Houston Electric, LLC v. Gulf Coast
Coalition of Cities, No. 03-05-00557-CV, 2008 Tex. App. LEXIS 2819, at *11 (Tex. App.—Austin
Apr. 17, 2008, no pet. h.) (op. on reh’g).
13
With this statutory scheme in mind, I examine the parties’ complaints regarding the
Commission’s determination of TCC’s stranded costs and other true-up balances.
C. Stranded Cost True-up
The legislature defined stranded costs as the positive excess of the net book value of
a utility’s generation assets over the market value of those assets. Tex. Util. Code Ann. § 39.251(7).
The parties raise several challenges to the Commission’s determinations regarding both the market
value and net book value of TCC’s generation assets.
1. Determination of market value
The Joint Intervenors and OPC/CCG challenge the Commission’s determinations
regarding the market value of TCC’s interest in the STP. As a preliminary matter, OPC argues that
the Commission erred in allowing TCC to recover stranded costs for the STP because there was no
evidence that the STP was an “uneconomic asset.”7 Assuming the Commission properly allowed
TCC to recover stranded costs for the STP, the Joint Intervenors and OPC/CCG argue that the
Commission erred in its market valuation of the STP because it failed to use the ECOM method
prescribed in section 39.262(i) for valuing nuclear assets. The Joint Intervenors also argue in the
alternative that the Commission erred in its conclusion that the STP auction was a bona fide third-
party transaction within the meaning of section 39.262(h).
7
I agree with TCC that CCG has failed to preserve this issue for review. Therefore, I only
address this issue to the extent it is raised by OPC.
14
(A) Was the STP an “uneconomic asset”?
OPC argues that TCC cannot recover stranded costs for its share of the STP because
the STP was not an “uneconomic asset.” In support of this argument, OPC cites to section
39.001(b)(2) of the PURA. In that section, the legislature found that it was in the public interest to
“allow utilities with uneconomic generation related assets and purchased power contracts to recover
the reasonable excess costs over market [value] of those assets and purchased power contracts.”
Tex. Util. Code Ann. § 39.001(b)(2) (emphasis added). Based on this language, OPC argues that
TCC was only permitted to recover stranded costs for its demonstrated “uneconomic generation
related assets.” See id. As a result, OPC argues that the Commission erred in allowing TCC to
recover stranded costs for the STP because “the undisputed evidence in the record shows that net
margins over the life of the STP far exceed the net book value of the plant.”
OPC’s argument involves a matter of statutory construction. When construing
a statute, our primary goal is to determine and give effect to the legislature’s intent. City of
San Antonio, 111 S.W.3d at 25. To determine legislative intent, we look to the statute as a whole,
as opposed to isolated provisions. Gonzalez, 82 S.W.3d at 327. In addition to the language relied
on by OPC in section 39.001(b)(2), section 39.251(7) of the PURA defines the term “stranded costs”
as “the positive excess of the net book value of generation assets over the market value of the assets,
taking into account all of the electric utility’s generation assets.” Tex. Util. Code Ann. § 39.251(7)
(emphasis added). Section 39.251(3) defines the term “generation assets” as “all assets associated
with the production of electricity, including generation plants, electrical interconnections of
the generation plant to the transmission system, fuel contracts, fuel transportation contracts, water
15
contracts, lands, surface or subsurface water rights, emissions related allowances, and gas pipeline
interconnections.” Id. § 39.251(3) (emphasis added). Section 39.252(a) provides that “[a]n electric
utility is allowed to recover all of its net, verifiable, nonmitigable stranded costs incurred in
purchasing power and providing electric generation service.” Id. § 39.252(a) (emphasis added).
When read together, these provisions allow a utility to recover all of its stranded costs
for generation related assets when the net book value exceeds the market value of those assets. See
id. §§ 39.251(3), (7), .252(a). None of these provisions includes the phrase “uneconomic assets,”
nor does the legislature otherwise limit the recovery of stranded costs to only “uneconomic assets.”
In section 39.252(a), the legislature expressly provided that a utility may recover “all of its net,
verifiable, nonmitigable stranded costs.” See id. § 39.252(a) (emphasis added). There is no
indication in other provisions of the PURA that the legislature intended to limit a utility’s recovery
of stranded costs by its use of the phrase “uneconomic assets” in section 39.001(b)(2). It does not
follow then that the legislature intended to limit recovery of stranded costs in the manner urged by
OPC. Because the STP is a generation asset and all generation assets must be valued to determine
TCC’s stranded costs, I conclude that the Commission properly determined that the STP was eligible
for inclusion in the calculation of TCC’s stranded costs. I would overrule OPC’s issue one.
(B) Was the Commission required to use the ECOM method to determine
the market value of the STP?
OPC/CCG and the Joint Intervenors argue that the Commission was required to use
the ECOM method in section 39.262(i) when determining the market value of the STP. OPC/CCG
argue that TCC must use the ECOM method to value its nuclear assets absent a stock valuation, and
16
that the sale-of-assets method can never be used for that purpose. In contrast, the Joint Intervenors
argue that because a utility has a duty to mitigate its stranded costs, the ECOM method in section
39.262(i) must be used to value nuclear assets unless another method is shown to produce lower
stranded costs.8
These arguments also involve a matter of statutory construction. As previously stated,
the primary objective when construing a statute is to ascertain and give effect to the legislature’s
intent. City of San Antonio, 111 S.W.3d at 25. To determine legislative intent, courts look to
the statute as a whole, as opposed to isolated provisions. Gonzalez, 82 S.W.3d at 327. A reviewing
court gives deference to the Commission’s interpretation of a statute it is charged with enforcing as
long as that interpretation is reasonable and consistent with the plain language of the statute. Tarrant
Appraisal Dist., 845 S.W.2d at 823; Steering Comms. for Cities, 42 S.W.3d at 300. Accordingly,
I begin with the plain language of the PURA.
In relevant part, section 39.262(h) provides, “Except as provided in Subsection (i) . . .
the affiliated power generation company shall quantify its stranded costs using one or more of the
following methods . . . .” Tex. Util. Code Ann. § 39.262(h). Section 39.262(h) goes on to specify
four methods a utility may use to quantify its stranded costs: sale-of-assets, stock valuation, partial
stock valuation, and exchange-of-assets. Id. § 39.262(h)(1)-(4). In addition, section 39.262(i)
provides, “Unless an electric utility or its affiliated power generation company combines all of its
remaining generation assets into one or more transferee corporations as described in Subsections
8
Contrary to the suggestions of TCC and the Commission, the record demonstrates that
AVH raised this claim in its motion for rehearing before the Commission and in its petition for
judicial review before the district court. Therefore, I would conclude that the Joint Intervenors have
preserved this claim for our review.
17
(h)(2) and (h)(3), the electric utility shall quantify its stranded costs for nuclear assets using the
ECOM method . . . .” Id. § 39.262(i).
The Commission determined that, when read together, these statutes allow TCC to
quantify its stranded costs for nuclear assets using any of the methods in section 39.262(h), including
the sale-of-assets method. The Commission adopted PUC Substantive Rule 25.264, which confirms
its interpretation allowing TCC to quantify its stranded costs for nuclear assets using the methods
established in section 39.262(h). Rule 25.264 states:
The market value of an affiliated power generation company’s nuclear assets may be
established by compliance with any of the four methods of quantification specified
in Public Utility Regulatory Act (PURA) § 39.262(h) and related requirements
specified in § 25.263 of this title (relating to True-up Proceeding). If the electric
utility or its affiliated power generation company values some of its assets using the
sale of assets or an exchange of assets, any remaining assets shall be combined in one
or more transferee corporations as described in PURA § 39.262(h)(2) and (3) for
purposes of determining their market value, or the electric utility or its affiliated
power generation company shall quantify its stranded costs for remaining nuclear
assets using the “excess costs over market” or ECOM method.
16 Tex. Admin. Code § 25.264 (2006) (Pub. Util. Comm’n). In its order adopting Rule 25.264, the
Commission explained:
This rule is necessary to firmly establish the methods that may be employed to
determine the stranded cost of nuclear power generation assets. In addition, the rule
is needed to serve the public interest and legislative policy stating that utilities with
uneconomic generation-related assets should be allowed to recover the reasonable
excess costs over market value of those assets. In order to assure that the market
value of nuclear generation assets is properly quantified in a manner that reduces, to
the extent possible, the amount of excess costs over market value for those assets, the
rule clarifies that a public utility and its affiliated companies may use any of the
valuation methods specified in PURA § 39.262(h) and (i) to quantify the market
value of nuclear generation assets.
18
Tex. Pub. Util. Comm’n, Rulemaking Proceeding Concerning Quantification of Stranded Costs
of Nuclear Generation Assets, Substantive Rule § 25.264, Docket No. 27464, Order at 2 (May 23,
2003).
The plain language of section 39.262(h) allows a utility or its affiliates to quantify
stranded costs “using one or more of the following methods,” including the sale-of-assets method.
Tex. Util. Code Ann. § 39.262(h). That section does not preclude a utility from using the sale-of-
assets method to quantify its stranded costs for nuclear generation assets. Id. Nor does the plain
language of section 39.262(i) require a utility to use the ECOM method to quantify its stranded costs
for nuclear generation assets. Id. § 39.262(i). By its use of the word “remaining,” the language of
section 39.262(i) presumes that it is a fallback provision and that a utility will use one of the four
methods in section 39.262(h) to quantify stranded costs for nuclear assets. Id. Only if a company
has “remaining” assets will section 39.262(i) come into play.
The definition of “market value” in section 39.251(4) likewise confirms this
interpretation. Section 39.251(4) defines market value “for nonnuclear assets and certain nuclear
assets, [as] the value the assets would have if bought and sold in a bona fide third-party transaction
or transactions on the open market under Section 39.262(h) or, for certain nuclear assets, as
described by Section 39.262(i), the value determined under the method provided by that subsection.”
Id. § 39.251(4). The plain language of section 39.251(4) contemplates that nuclear assets might be
“bought and sold in a bona fide third-party transaction.” Id.
The Commission’s interpretation allowing TCC to quantify its stranded costs for
nuclear assets using the sale-of-assets method was reasonable and consistent with the plain language
19
of the statute. In addition, PUC Rule 25.264 comports with the statute.9 For these reasons, I would
overrule OPC/CCG’s issue two.
To the extent the Joint Intervenors argue that TCC was required to use the ECOM
method to quantify its stranded costs for nuclear assets because that method would have produced
lower stranded costs, I would likewise reject that claim. To adopt the Joint Intervenors’ argument
would require the utility to know in advance which method would produce the least amount of
stranded costs. It is only in hindsight that a utility will know whether the method it has chosen to
quantify its stranded costs will produce lower stranded costs than the ECOM method. The plain
language of section 39.262(h) does not require a utility to engage in forecasting the future. Although
the legislature required utilities to mitigate their potential stranded costs and provided that a utility
may recover only its “net, verifiable, nonmitigable stranded costs,” the legislature also gave the
utility the option of choosing which method it would use to quantify stranded costs. See Tex. Util.
Code Ann. § 39.262(h). That the utility had this choice is confirmed by the mandatory language of
section 39.262(h), which states that “the affiliated power generation company shall quantify its
stranded costs using one of the following methods.” Id. § 39.262(h). I would overrule Joint
Intervenors’ issue three.
9
Because I conclude that the Commission’s interpretation is reasonable and consistent with
the statute and that the rule comports with the statute, I would not reach the issue of whether
OPC/CCG’s claim is an impermissible collateral attack on the validity of the rule.
20
(C) Was the sale of TCC’s share of the STP a bona fide third-party
transaction under a competitive offering?
In the alternative, the Joint Intervenors argue that the Commission erred in
its conclusion that TCC’s sale of its share of the STP was a bona fide third-party transaction under
a competitive offering as required under section 39.262(h). This argument is without merit.
The primary complaint of the Joint Intervenors is that the Commission failed to
follow its precedent in the Texas-New Mexico Power true-up, where the Commission determined
that TNMP’s sale of generation assets was not a bona fide third-party transaction under a competitive
offering. But the record reflects that the facts of TCC’s sale of the STP differed from TNMP’s sale
of its generation assets. The Commission determined that one of the most important aspects for
determining whether a transaction meets the statutory requirements is whether the utility acquires
competent and independent advice before and during the transaction. The record reflects that TCC
chose several financial advisors to assist with the sale of its share of the STP, not just one, as TNMP
did. The record also reflects that TCC’s choice of financial advisors was not motivated by an inside
connection as was TNMP’s.10 The Commission also noted that two additional strengths of TCC’s
sales process not present in that of TNMP’s was the marketing of the offering and the aggressive
negotiations with bidders. The Commission determined that the basic structure of TCC’s process
promoted competitive and good-faith participation by bidders. Because the facts of TCC’s sales
process differed substantially from that of TNMP’s, the Commission was not bound to follow its
10
In TNMP’s case, TNMP chose Laurel Hill as its only financial advisor based on
the merger agreement between TNMP’s parent company TNP Enterprises and ST Acquisition
Corporation. Because the managing director of Laurel Hill was also the chief financial officer of
TNP Enterprises, the Commission concluded that Laurel Hill was chosen because of its inherent
relationship with TNMP’s parent company and not because it offered significant expertise in the sale
of a utility’s generation assets.
21
precedent in that case or, in any event, it did not constitute precedent as to this transaction. On this
record, there was a reasonable basis to support the Commission’s determination that TCC’s sale of
its share of the STP was a bona fide third-party transaction under a competitive offering in
compliance with section 39.262(h). I would overrule Joint Intervenors’ issue four.
2. Adjustments to net book value
(A) Commercial unreasonableness
In its final order, the Commission made two adjustments to the net book value of
TCC’s generation assets to address what it determined to be commercial unreasonableness and the
failure to mitigate stranded costs by TCC. Specifically, the Commission reduced the net book value
of TCC’s Coleto Creek Coal Plant by $8 million and reduced the net book value of TCC’s share in
the STP by $68.7 million. The district court found that these two adjustments were barred by
section 39.252(d) of the PURA. The Commission and the Joint Intervenors appeal the reversal of
these two adjustments. In addition, the Joint Intervenors contend that the Commission’s calculation
of these two adjustments was in error. In a related issue, the Joint Intervenors also argue that the
Commission erred in failing to adjust net book value for TCC’s commercial unreasonableness in
failing to use “bridge power sales agreements.”
For the reasons stated in Justice Pemberton’s opinion, a majority of this Court affirms
the district court’s judgment that section 39.252(d) of the PURA precludes the Commission
from making adjustments to the net book value of TCC’s generation assets for “commercial
unreasonableness.”11 I disagree with the majority’s decision.
11
For this reason, Justices Puryear and Pemberton do not join parts II.C.2(A)(i) through (iii)
of this opinion, except to the extent we overrule Joint Intervenors’ issue seven and affirm the district
22
As an initial matter, these claims require the Court to consider the Commission’s
authority under section 39.252(d) to make adjustments to the net book value of TCC’s generation
assets—a question this Court already decided in Reliant I, 101 S.W.3d at 149. Section 39.252(d)
provides:
An electric utility shall pursue commercially reasonable means to reduce its potential
stranded costs, including good faith attempts to renegotiate above-cost fuel and
purchased power contracts or the exercise of normal business practices to protect the
value of its assets. The commission shall consider the utility’s efforts under this
subsection when determining the amount of the utility’s stranded costs; provided,
however, that nothing in this section authorizes the commission to substitute its
judgment for a market valuation of generation assets determined under Sections
39.262(h) and (i).
Tex. Util. Code Ann. § 39.252(d). In Reliant I, this Court held that section 39.252(d) authorized
the Commission to make adjustments to net book value when a utility does not pursue commercially
reasonable means to reduce potential stranded costs. See 101 S.W.3d at 149. We further observed
that the relevant statutory goal was calculating not just an accurate stranded cost amount, but
“calculating an accurate ‘verifiable, non-mitigable stranded cost[]’ amount.” Id. (quoting Tex. Util.
Code Ann. § 39.252(d)). And we recognized that “[c]ompliance with the duty to pursue
commercially reasonable means to mitigate its potential stranded costs is what makes stranded costs
non-mitigable.” See id. Given the plain language of section 39.252(d), we held in Reliant I that
nothing in section 39.252(d) prohibits the Commission from reducing net book value if it concludes
that a utility fails to comply with the duty to mitigate potential stranded costs. Id.
court’s judgment and the Commission’s final order regarding the use of bridge power sales
agreements.
23
I disagree with TCC’s assertion that Reliant I “does not address the issue of when
the Commission may properly adjust net book value.” This Court’s holding in Reliant I made clear
that the Commission may properly adjust net book value when it determines that a utility has not
pursued commercially reasonable means to reduce its potential stranded costs. Id. I see no reason
to re-examine that holding here. Accordingly, I would reaffirm this Court’s prior holding in Reliant
I that section 39.252(d) allows the Commission to adjust the net book value of a utility’s generation
assets when the utility fails to “pursue commercially reasonably means to reduce its potential
stranded costs.” Id.; see also Tex. Util. Code Ann. § 39.252(d).
This Court also considered the Commission’s authority to adjust net book value for
commercial unreasonableness in the CenterPoint true-up appeal. See CenterPoint, 2008 Tex. App.
LEXIS 2819, at *82-83. In CenterPoint, the Commission’s final order set forth a primary and
alternative holding. Id. at *21-23. Under its primary holding, the Commission adopted its own
market valuation of CenterPoint’s generation assets based on its finding that CenterPoint had failed
to establish the market value of those assets as required under section 39.262(h). Id. at *23, *30-35.
Under its alternative holding, the Commission adopted the market value proposed by CenterPoint,
but made reductions to net book value based on commercial unreasonableness. Id. at *23, *79. This
Court considered whether the Commission’s reductions to net book value for commercial
unreasonableness should also be applied to its primary holding. Id. at *79-84. This Court concluded
that reductions to net book value for commercially unreasonable behavior were not meant to be
punitive in nature. Id. at *82. The Court stated that where a utility’s commercially unreasonable
behavior benefits the utility financially and lessens the impact of stranded costs by increasing
24
the utility’s stranded cost recovery, the amount of stranded costs recovered by the utility should be
modified to capture the utility’s unreasonable behavior. Id. The Court further explained that, if
the commercially unreasonable behavior has no financial impact or, if the financial impact is
irrelevant to or has already been accounted for in the valuation of the utility’s generation assets,
any adjustment to the net book value of the utility’s generation assets would be contrary to the
legislative directive. Id.
This Court ultimately concluded that the Commission’s decision in the CenterPoint
true-up proceeding to limit the adjustments to net book value to its alternative holding was
reasonable because the negative effects of any commercially unreasonable behavior on the part of
CenterPoint had no effect on the valuation of CenterPoint’s generation assets. Id. at *83-84. But
this Court’s statements in CenterPoint suggest that an adjustment for commercial unreasonableness
is appropriate if the valuation method chosen does not account for the commercially unreasonable
behavior and the utility’s commercially unreasonable behavior benefits the utility unfairly by
increasing its stranded cost recovery. See id. at *82.
TCC argues that section 39.252(d) only imposes a duty to mitigate potential stranded
costs prior to a utility’s divestiture of its generation assets and that a utility has no duty to mitigate
potential stranded costs during or after divestiture. Thus, because the Commission determined that
TCC’s sales of the Coleto Creek Coal Plant and its share of the STP were bona fide third-party
transactions under a competitive offering within the meaning of section 39.262(h)(1), TCC maintains
that the Commission could not thereafter adjust the net book value of these assets for commercial
unreasonableness. TCC’s argument is essentially one of timing—namely that a utility is required
25
to pursue commercially reasonable means to mitigate stranded costs only up to the point that it
decides to sell its generation assets, but not thereafter.
This is not what the legislature provided. See Tex. Util. Code Ann. § 39.252(d).
Nowhere in section 39.252(d) does the legislature limit a utility’s duty to mitigate potential stranded
costs in the manner urged by TCC. The determination of whether a sale is a bona fide third-party
transaction under a competitive offering is distinct from the determination of whether TCC used
commercially reasonable means to mitigate stranded costs. As the Commission explained in its final
order, the analysis of whether a sale is a bona fide third-party transaction under a competitive
offering is directed towards the requirements of section 39.262(h)(1) in determining the market
value of generation assets. See id. § 39.262(h)(1). In contrast, a determination of commercial
reasonableness of a company’s mitigation efforts is made under section 39.252(d), and applies not
only to the sales process, but also to other actions that the seller may take to mitigate stranded costs.
See id. § 39.252(d). I would hold that the Commission’s finding that TCC’s sales of its generation
assets were bona fide third-party transactions under a competitive offering does not preclude it
from determining that TCC’s conduct undertaken in pursuit of those sales was commercially
unreasonable. Under a plain reading of section 39.252(d), the former simply does not foreclose
the latter. See id.
To the extent it holds otherwise, the majority restricts a utility’s duty to mitigate
stranded costs in a manner not contemplated by the legislature. There is nothing temporal in the
statute that precludes the Commission from adjusting the net book value of a utility’s generation
assets based on commercially unreasonable conduct occurring before, during, or after an asset
26
sale—particularly where the market valuation method employed by TCC does not take into account
its commercially unreasonable behavior. Accordingly, I would sustain the Commission’s issue one
and Joint Intervenor’s issue one, and I would reverse the district court’s judgment that section
39.252(d) prohibits the Commission’s adjustments to net book value. Because the majority does not,
I respectfully dissent.
As a result of my conclusion that section 39.252(d) does not prohibit the
Commission’s adjustments to net book value, it is necessary to consider the parties’ challenges to
the Commission’s calculation of individual adjustments to net book value and whether the valuation
method chosen by TCC accounts for the alleged commercially unreasonable behavior found by
the Commission. See CenterPoint, 2008 Tex. App. LEXIS 2819, at *81-84. Unlike its order
in CenterPoint, the Commission adopted only one holding in its final order here. In that order,
the Commission adopted two adjustments for commercial unreasonableness: (1) an $8 million
reduction to net book value based on TCC’s decision to bundle and sell the Coleto Creek Coal Plant
with other less desirable generation assets; and (2) a $68.7 million reduction to net book value based
on TCC’s failure to develop an estimate of the value of its share of the STP, the corresponding lack
of knowledge of the STP’s intrinsic value, and the lack of a walk-away price for its share of the STP.
(i) TCC’s choice to bundle the gas plants with Coleto Creek
The record shows and TCC admits that its decision to bundle the gas plants with
the Coleto Creek Coal Plant for purposes of divestiture decreased the market value of the Coleto
Creek Coal Plant by $8 million—the amount of the Commission’s adjustment for commercial
unreasonableness. The Commission accepted TCC’s proposal to reduce net book value for Coleto
27
Creek by $8 million and rejected the intervenors’ request for a much greater reduction. The
$8 million reduction to net book value was based on the difference between Sempra’s bid for the
Coleto Creek Coal Plant alone and its bid for the bundle of plants, which was $8 million lower than
the stand-alone bid for Coleto Creek.
TCC’s decision to bundle the gas plants with Coleto Creek financially benefitted the
utility and lessened the impact of stranded costs. Moreover, the valuation method chosen—the total
net value realized from the asset sale—did not account for the decreased market value caused
by TCC’s decision to bundle the plants. Because the effect of TCC’s commercially unreasonable
decision to bundle the Coleto Creek Coal Plant with other less desirable assets was not captured in
the valuation method chosen by TCC, I would conclude that the Commission’s $8 million reduction
to TCC’s net book value for the Coleto Creek Coal Plant was appropriate. I would therefore
consider the Joint Intervenors’ challenge to this adjustment.
The Joint Intervenors challenge the Commission’s $8 million adjustment to the net
book value of the Coleto Creek Coal Plant on the grounds that it is not supported by substantial
evidence. They argue that the Commission’s adjustment to the net book value of Coleto Creek
should have been higher than $8 million.
When conducting a substantial evidence review, a reviewing court must determine
whether the evidence as a whole is such that reasonable minds could have reached the conclusion
reached by the Commission. City of El Paso, 883 S.W.2d at 186; Sizemore, 759 S.W.2d at 116. The
true test is not whether we believe the agency reached the correct conclusion, but whether
some reasonable basis exists in the record for the action taken by the agency. Charter Medical,
28
665 S.W.2d at 452. The Commission is the sole judge of the weight to be accorded the testimony
of each witness. Central Power & Light Co., 36 S.W.3d at 561. We may not substitute our
judgment for that of the Commission on the weight of the evidence on questions committed to the
Commission’s discretion. Tex. Gov’t Code Ann. § 2001.174; see Charter Medical, 665 S.W.2d at
452; H.G. Sledge, 36 S.W.3d at 602. The Commission was entitled to accept or reject in whole or
in part the testimony of the various witnesses who testified. See City of Corpus Christi v. Public
Util. Comm’n, 188 S.W.3d 681, 695 (Tex. App.—Austin 2005, pet. denied); Central Power & Light
Co., 36 S.W.3d at 561.
The Commission concluded that TCC’s action of bundling Coleto Creek with the old
gas-fired and hydroelectric plants adversely affected the amount bid for Coleto Creek, thereby
increasing TCC’s stranded costs. The prevailing bidder, Sempra/Riverstone, submitted a bid for
Coleto Creek alone and a separate bid for the bundled plants. The bid for Coleto Creek alone was
$8 million higher than the bid for the bundled plants together. Because the bids were virtually
contemporaneous and were made by the same bidder for the same facilities, the Commission
concluded that TCC’s decision to bundle its gas-fired and hydroelectric plants with Coleto Creek
increased TCC’s stranded costs by $8 million. Accordingly, the Commission reduced TCC’s net
book value by $8 million. The Joint Intervenors complain that this adjustment was not high enough
because other evidence in the record suggested that TCC could have received an additional $68.2
to $87.2 million for Coleto Creek.12 Because the Commission was entitled to accept or reject all or
12
Cities witness Scott Norwood recommended a $68.2 million reduction to net book value
based on his comparison of what TCC received for the Oklaunion Coal Plant and what it received
for Coleto Creek; CCG witness Paul Wielgus testified that TCC could have received an additional
$70 million for Coleto Creek; and consistent with Norwood’s testimony regarding the comparison
29
part of the testimony presented, see City of Corpus Christi, 188 S.W.3d at 695; Central Power
& Light Co., 36 S.W.3d at 561, I would conclude that the Commission’s decision to reduce the net
book value of the Coleto Creek Coal Plant was supported by substantial evidence, and I would
overrule Joint Intervenors’ issue five.
(ii) Failure to develop estimated value of the STP share
The record shows that TCC never developed an estimate of the value of its share of
the STP that was supported by economic or financial analysis. Thus, prior to the auction of its share
of the STP, TCC had not formulated how much its share was worth.13 Without this information,
TCC could not make an informed decision as to whether the negotiated sales price was reasonable.
The valuation method chosen could not have accounted for TCC’s lack of knowledge.
The Commission determined that TCC’s failure to develop an estimate of the value
of its share of the STP, the corresponding lack of knowledge of the STP’s intrinsic value, and the
lack of a walk-away price for the STP was commercially unreasonable and amounted to a failure to
mitigate stranded costs. To account for TCC’s commercial unreasonableness, the Commission
reduced the net book value of TCC’s share in the STP by $68.7 million. Under the standard set forth
in CenterPoint, I would conclude that the Commission’s reduction to TCC’s net book value for its
share of the STP was appropriate. I would therefore consider the Joint Intervenors’ challenge to this
adjustment.
between Oklaunion and Coleto Creek, OPC witness David Rode recommended a reduction to net
book value of $87.2 million.
13
It is illogical to assume that a reasonable seller would not want to know the value of what
he is selling.
30
The Joint Intervenors argue that the Commission’s adjustment should have been
higher. We review the Commission’s adjustment under the substantial evidence rule, and we
presume that the Commission’s determination is supported by substantial evidence. City of El Paso,
883 S.W.2d at 187; Office of Pub. Util. Counsel v. Public Util. Comm’n, 183 S.W.3d 555, 567
(Tex. App.—Austin 2006, pet. denied). The Joint Intervenors have the burden of proving otherwise.
Office of Pub. Util. Counsel, 183 S.W.3d at 567.
The record reflects that the Commission calculated the adjustment to net book value
for TCC’s share of the STP based on the SEC filing of GC Power,14 the “Project Crayola”
documents,15 and a comparison of the pricing differential between Texas Genco’s16 sale of its share
in the STP and TCC’s sale of its share in the STP. GC Power’s SEC filing states, “The purchase
price for the nuclear acquisition . . . was $707.6 million, which includes $700 million in cash paid
to Texas Genco Holdings, Inc. and approximately $7.6 million in acquisition costs.” The “Project
Crayola” documents likewise demonstrated that the price of Texas Genco’s sale of its share in the
STP was $700 million for 1100 MW, or approximately $636/kW. This was $109/kW higher than
the price of TCC’s sale to Cameco for $527/kW. The Commission calculated its adjustment to net
book value by multiplying the $109/kW difference times TCC’s 630 MW share of the STP, which
produced an adjustment of $68.7 million.
14
GC Power purchased Texas Genco’s share of the STP.
15
The “Project Crayola” documents were admitted without objection in the proceedings
before the Commission.
16
Texas Genco was a co-owner of the STP and exercised its right of first refusal to purchase
approximately 330 MW of TCC’s share in the STP. After this purchase, Texas Genco owned
approximately 1100 MW of the STP’s total capacity, which it then sold to a third party.
31
The Joint Intervenors argue that this adjustment was too low because Texas Genco
actually received more than $636/kW for the sale of its share in the STP. The Joint Intervenors argue
that the SEC filing shows that Texas Genco received $700 million for its original 770 MW share of
the STP, not including the 330 MW it received when exercising its right of first refusal to purchase
a portion of TCC’s share. But, as explained in the rebuttal testimony of TCC witness Mujeeb Qazi,
the Joint Intervenors misconstrue the SEC filing relied upon by the Commission to determine
the price that Texas Genco received for its share of the STP. As Qazi testified, the sale of Texas
Genco’s share of the STP included the 330 MW that it received from TCC under the right of first
refusal; thus, Texas Genco sold the entire 1100 MW share of the STP to GC power for $700 million.
The Commission is the sole judge of the weight to be accorded the testimony of each witness.
Central Power & Light Co., 36 S.W.3d at 561. The Commission was entitled to accept or reject in
whole or in part the testimony of the various witnesses who testified. See City of Corpus Christi,
188 S.W.3d at 695; Central Power & Light Co., 36 S.W.3d at 561. We may not substitute our
judgment for that of the Commission on the weight of the evidence on questions committed to the
Commission’s discretion. Tex. Gov’t Code Ann. § 2001.174; see Charter Medical, 665 S.W.2d at
452; H.G. Sledge, 36 S.W.3d at 602. Based upon Qazi’s testimony, I would conclude that there is
a reasonable basis in the record to support the Commission’s $68.7 million adjustment to the net
book value of TCC’s share of the STP, and I would overrule Joint Intervenors’ issue two.
(iii) Bridge Power Sales Agreements
In their seventh issue on appeal, the Joint Intervenors assert that the Commission
erred in failing to adjust net book value for TCC’s commercial unreasonableness in failing to use
32
bridge power sales agreements.17 According to the Joint Intervenors, the Commission’s failure to
require TCC to use bridge power sales agreements resulted in TCC’s failure to mitigate its potential
stranded costs and allowed TCC to overrecover stranded costs in violation of sections 39.252(d) and
39.262(a) of the PURA. Because TCC retained the profits from the interim power sales, the Joint
Intervenors argue that, as a result of TCC’s failure to use bridge power sales agreements, the
Commission should have reduced TCC’s stranded cost recovery by $206 million.
Applying the standard set forth in CenterPoint, however, I would conclude that
TCC’s failure to use bridge power sales agreements does not warrant an adjustment for commercial
unreasonableness. Because TCC’s failure to use such agreements allowed TCC to retain the profits
from power sales prior to closing the asset sale, the failure to use such agreements was accounted
for in the valuation method chosen in the form of a lower asset sales price. I would overrule Joint
Intervenors’ issue seven.
(B) Inclusion of construction work in progress
The Commission included in net book value the amount that TCC had spent on
generation related construction work in progress as of December 31, 2001.18 In their sixth issue, the
Joint Intervenors argue that the Commission erred by including CWIP in the net book value of
17
A bridge power sales agreement “would have enabled the buyers of TCC’s generating
units to sell power from those units until the sales were finalized, with TCC being compensated
with a higher asset-sale price.” Stated differently, the buyers, not TCC, would have received the
benefit of the interim power sales and would have paid a higher purchase price to TCC for its
generation assets.
18
This amount was $53,588,063, plus interest, and included only those CWIP amounts that
TCC had spent as of December 31, 2001. It did not include projected costs for unfinished projects.
33
TCC’s generation assets. Specifically, the Joint Intervenors argue that the Commission failed to
show that the inclusion of CWIP satisfied the requirements of section 36.05419 of the PURA and
that these requirements were made applicable to the calculation of TCC’s stranded costs through
section 39.260.20
This Court recently rejected the same claim in our consideration of the appeal of
the true-up proceeding of CenterPoint Energy. See CenterPoint, 2008 Tex. App. LEXIS 2819, at
*118-26. In CenterPoint, we upheld the Commission’s inclusion of CWIP in net book value
and explained that the Commission’s decision was proper for several reasons. Id. at *121, *126.
19
Section 36.054 states:
(a) Construction work in progress, at cost as recorded on the electric utility’s
books, may be included in the utility’s rate base. The inclusion of
construction work in progress is an exceptional form of rate relief that the
regulatory authority may grant only if the utility demonstrates that inclusion
is necessary to the utility’s financial integrity.
(b) Construction work in progress may not be included in the rate base for a
major project under construction to the extent that the project has been
inefficiently or imprudently planned or managed.
Tex. Util. Code Ann. § 36.054.
20
Section 39.260 states:
(a) The definition and identification of invested capital and other terms used in
this subchapter and Subchapter G that affect the net book value of generation
assets and the treatment of transactions performed under Section 35.035 and
other transactions authorized by this title or approved by the regulatory
authority that affect the net book value of generation assets during the freeze
period shall be treated in accordance with generally accepted accounting
principles as modified by regulatory accounting rules generally applicable to
utilities.
Tex. Util. Code Ann. § 39.260.
34
We rejected the construction urged by the Joint Intervenors in CenterPoint on the ground that it
ignored the “unique role” of section 36.054 in the ratemaking context. Id. at *122-23. We explained
that were we to adopt the construction urged by the Joint Intervenors, we would forever deny a
utility’s right to recover its CWIP expenses—a result not contemplated by the legislature when it
allowed utilities to recover “all” of their stranded costs. See id. at *123-24 (citing Tex. Util. Code
Ann. § 39.252(a)). We also concluded that the plain language of section 39.260 did not incorporate
the requirements of section 36.054 into the Commission’s determination of stranded costs because
those requirements do not relate to any type of accounting rule or principle. Id. Finally, we
concluded that the Commission’s rule regarding stranded cost recovery includes CWIP in net book
value but makes no mention of the requirements in section 36.054. Id. at *125. Because the Joint
Intervenors make the same arguments this Court previously rejected in CenterPoint, I would overrule
Joint Intervenors’ issue six.
D. Excess Earnings/EMCs and Interest
I next turn to the parties’ claims regarding excess earnings and excess mitigation
credits. In their third issue, OPC/CCG argue that the Commission erred in failing to reduce TCC’s
stranded cost recovery by TCC’s excess earnings in 1999-2001 as required by sections 39.254 and
39.262(a) of the PURA. Additionally, the Joint Intervenors argue that the Commission erred in its
failure to reduce net book value by the amount of excess mitigation credits paid to TCC’s affiliated
retail electric provider—CPL Retail Energy. In a related claim, TCC argues that the district court
erred in affirming the Commission’s order because the Commission required TCC to pay interest
twice on the same excess earnings.
35
The record reflects that TCC had $42,209,382 of excess earnings during 1999-2001.
The Commission applied $860,765 as a reduction in the net book value of TCC’s generation assets
as required under section 39.254 of the PURA. The remaining $41,348,617 of excess earnings was
paid by TCC to its affiliated retail electric provider and other retail electric providers in the form of
excess mitigation credits. The record reflects that TCC paid $21,351,322 to its affiliated REP CPL
Retail Energy.21 OPC/CCG contend that the entire amount of excess mitigation credits should be
applied to reduce the net book value of TCC’s generation assets, thereby reducing TCC’s stranded
cost recovery. The Joint Intervenors agree, but they also argue in the alternative that, at a minimum,
the Commission should have reduced TCC’s stranded cost recovery by the amount of excess
mitigation credits paid to CPL Retail Energy.
This Court considered claims similar to those raised by OPC/CCG and the Joint
Intervenors in CenterPoint. See 2008 Tex. App. LEXIS 2819, at *85-101. We held that allowing
the utility to recover as stranded costs the amounts paid to its affiliated REP would allow the utility
to overrecover stranded costs in violation of section 39.262(a). Id. at *98-100. We explained that
section 39.262 of the PURA requires the Commission to treat the electric utility and its affiliated
REP as one entity for the purpose of stranded cost recovery. Id. at *98-99. Therefore, to the extent
a utility’s affiliated REP was allowed to retain excess mitigation credits, the utility could not recover
that amount as stranded costs because allowing such a recovery would result in an overrecovery of
stranded costs in violation of section 39.262(a). Id. at *99-100.
21
CPL Retail Energy received a total of $29,616,249, including interest of $8,264,927.
36
Adhering to this Court’s decision in CenterPoint, I would conclude that the
Commission erred in allowing TCC to recover as stranded costs those amounts paid to CPL Retail
Energy as excess mitigation credits, but consideration of these claims must also take into account
this Court’s prior decision in City of Corpus Christi v. Public Utility Commission, 188 S.W.3d
681 (Tex. App.—Austin 2005, pet. denied). In City of Corpus Christi, this Court held that the
Commission exceeded its statutory authority when it ordered TCC to pay excess mitigation credits
in the first instance. 188 S.W.3d at 689. The supreme court denied the Commission’s petition for
review on April 29, 2007—more than one year after the Commission’s final order in the instant true-
up proceedings. Accordingly, we are called upon to reconcile our earlier decision in City of Corpus
Christi with our more recent decision in CenterPoint, and the Commission’s final order in TCC’s
true-up proceedings.
This analysis begins with the Commission’s final order. Finding that the appellate
process in City of Corpus Christi was “not yet complete,” the Commission “decline[d] to provide
for [an] adjustment [to TCC’s stranded costs] in this Order.” Stated differently, the Commission did
not consider the effects of our decision in City of Corpus Christi, much less our recent decision in
CenterPoint, when it finalized TCC’s stranded costs in the instant true-up proceeding. Because the
Commission should be given the opportunity to consider the effects of our decisions in City of
Corpus Christi and CenterPoint in the first instance,22 I would reverse the district court’s judgment
to the extent it affirmed the Commission’s order regarding the treatment of excess mitigation credits,
22
The legislature has charged the Commission with the task of finalizing each utility’s
stranded costs. See Tex. Util. Code Ann. § 39.262(c).
37
and remand this issue, including the claims raised in OPC/CCG’s issue three and Joint Intervenors’
issue ten, to the Commission for further proceedings.
For the same reasons, I would reverse the district court judgment to the extent it
affirmed the Commission’s order regarding the treatment of interest as it relates to the payment of
excess mitigation credits, and remand this issue, including the claim raised in TCC’s issue three, to
the Commission for further proceedings.
E. Interest on Stranded Costs
In its final judgment, the district court concluded that the Commission “erred in
applying Rule [16 Tex. Admin. Code §] 25.263 to determine the interest rate on stranded costs,
because the Supreme Court invalidated the rule in [CenterPoint Energy].” Both the Commission
and TCC appeal this portion of the district court’s judgment. Because I conclude that the supreme
court’s decision in CenterPoint Energy did not invalidate that portion of the rule regarding the
interest rate, I would reverse the judgment of the district court. See 143 S.W.3d at 84.
In relevant part, the Commission’s true-up rule, PUC Substantive Rule 25.263,
provides:
The TDU shall be allowed to recover, or shall be liable for, carrying costs on the
true-up balance. This provision shall apply to all amounts the commission has
authorized to be collected under this section that have not been securitized. Carrying
costs on the unrecovered true-up balance shall be calculated from January 1, 2002,
until the true-up balance is fully recovered. Based on the filing described below that
is made within 30 days of the effective date of this rule, carrying costs shall be
calculated using an interest rate determined as follows.
(A) The TDU shall file an application to adjust the carrying costs and amend its
CTC tariff on a prospective basis in conformance with this paragraph within
38
30 days of the effective date of an amendment to this paragraph. The
establishment of the interest rate used to calculate carrying charges shall be
based upon the following . . . .
16 Tex. Admin. Code § 25.263(l)(3). The rule goes on to establish the proper interest rate to be
applied to a utility’s stranded costs using specific formulaic requirements, none of which are at issue
here, or were at issue before the supreme court in CenterPoint Energy.
In CenterPoint Energy, the supreme court declared “that Rule 25.263(l)(3) is invalid.”
143 S.W.3d at 99. At first glance, this statement would appear to invalidate the entire rule, including
that portion of the rule regarding the interest rate to be applied to a utility’s stranded costs. Upon
closer examination of the supreme court’s opinion, however, I am not persuaded that the supreme
court spoke so broadly.
It is clear from the supreme court’s opinion that the only issue before the court in
CenterPoint Energy was the date on which a utility begins to accrue interest on its stranded cost
balance. As originally adopted, the Commission’s rule provided that a utility did not begin to accrue
interest on its stranded costs until the Commission issued a final order in the utility’s stranded
cost true-up proceeding. 26 Tex. Reg. 10498 (2001) (proposed June 15, 2001) (Pub. Util. Comm’n);
see also CenterPoint Energy, 143 S.W.3d at 83. The supreme court determined that the
Commission’s rule was invalid because it was inconsistent with the legislative intent that a utility
recover all of its net, verifiable, non-mitigable stranded costs, “that ‘exist on the last day of the freeze
period [December 31, 2001],’” which would include carrying costs from the first date of retail
competition, or January 1, 2002. CenterPoint Energy, 143 S.W.3d at 84 (quoting Tex. Util. Code
Ann. § 39.201(g)). Thus, despite its broad statement that rule 25.263(l)(3) was invalid, it is clear
39
from the text of the supreme court’s opinion that the court only invalidated that portion of the rule
relating to the date on which carrying costs, or interest, began to accrue. See id.
Furthermore, the Commission’s rules have a severability clause. See 16 Tex. Admin.
Code § 25.3 (2007) (Pub. Util. Comm’n). The severability clause states,
If any provision of this chapter is held invalid, such invalidity shall not affect other
provisions or applications of this chapter which can be given effect without the
invalid provision or application, and to this end, the provisions of this chapter are
declared to be severable.
Id. § 25.3(a). To determine whether it is proper to sever that portion of rule 25.263 invalidated by
the supreme court in CenterPoint Energy from the remainder of the rule we apply a two-prong test:
(1) will the function of the regulatory statute as a whole be impaired without the
invalid part of the rule; and
(2) is there any indication that the agency would not have adopted the rule but for
the invalid part?
See Texas Dep’t of Banking v. Restland Funeral Home, Inc., 847 S.W.2d 680, 683
(Tex. App.—Austin 1993, no writ) (citing K Mart Corp. v. Cartier, Inc., 486 U.S. 281, 294-95
(1988)). If, in the court’s view, the answer to either inquiry is “yes,” then severance is not justified
and the entire rule must fall. Id.
Applying this test in the context of rule 25.263(l)(3), I would conclude that severance
is justified. The function of the rule as a whole will not be impaired without the invalid part of the
rule, and there is no indication that the Commission would not have adopted the rule but for the
portion invalidated by the supreme court. See id. I would sustain the Commission’s issue two and
40
TCC’s issue four, reverse the district court’s judgment, and render judgment affirming the
Commission’s final order on this issue.
F. Evidentiary Ruling
In its third issue on appeal, the Commission seeks reversal of that portion of the
district court’s judgment finding that the Commission erred in striking the expert report of Ross A.
Sollosy, a consultant hired to advise the Commission and paid for by the Commission. The Joint
Intervenors also appeal the district court’s judgment on this issue. For the reasons that follow, I
agree with the Commission and the Joint Intervenors that the district court’s judgment was in error.
This Court reviews the Commission’s decision to admit or exclude evidence for abuse
of discretion—the same standard we apply to trial courts. City of Amarillo v. Railroad Comm’n,
894 S.W.2d 491, 495 (Tex. App.—Austin 1995, writ denied). An agency has broad discretion when
deciding whether to admit expert testimony in an administrative hearing, and its decision will not
be disturbed absent an abuse of discretion. Fay-Ray Corp. v. Texas Alcoholic Bev. Comm’n,
959 S.W.2d 362, 367 (Tex. App.—Austin 1998, no pet.).
The record reflects that Sollosy and his firm Navigant were hired to advise the
Commission and its staff regarding TCC’s sale of its share of the STP and other generation assets.
During the hearing before the Commissioners, Commission staff introduced Sollosy’s expert report
into evidence. In addition, TCC introduced excerpts from Sollosy’s deposition testimony, a
deposition exhibit, and Sollosy’s expert report. TCC’s introduction of Sollosy’s testimony, exhibit,
and report was cumulative of other evidence and testimony provided by other TCC witnesses. After
Sollosy’s testimony and report were introduced into evidence, it was discovered that Navigant, in its
41
responses to the parties’ requests for information (RFIs), had failed to produce documents responsive
to the parties’ RFIs. Initially, the Commissioners asked Sollosy to review his RFI responses
and supplement them as necessary. Several days later, Navigant’s general counsel appeared
unexpectedly at the hearing and disclosed more extensive problems. He admitted that Navigant’s
responses to the RFIs were misleading and incomplete because several boxes of material related to
Navigant’s prior involvement with electric generation asset sales, as well as information relied upon
by Sollosy in forming his opinions regarding TCC’s asset sales and preparing his expert report, had
not been produced. Navigant’s general counsel indicated that there were potentially sixty to one
hundred boxes of responsive materials that had not been produced. He stated that these documents
were, at the time, being pulled from a warehouse and reviewed and redacted and that they would be
available in Austin in a week.23
In response to this development, various intervenors moved to strike Sollosy’s
testimony and expert report because they had not had the opportunity to review these documents in
preparation of their case before cross-examining Sollosy. The Commission granted the motion to
strike.24 As a result of this decision, the Commission struck, among other exhibits, TCC Exhibit 28,
including excerpts from Sollosy’s deposition testimony, a deposition exhibit, and Sollosy’s
expert report.
23
The record reflected that some of the documents relating to Navigant’s prior experience
in the sale of generation assets had been returned to its clients and that copies were not kept.
Navigant’s general counsel stated that Navigant could “probably get them back.”
24
I disagree with TCC’s assertion on appeal that the Commission did not strike the Cities’
exhibits of Sollosy’s testimony because the hearing transcript reflects that Sollosy’s testimony and
report were struck for all purposes except for TCC’s offer of proof.
42
TCC argues on appeal that we should affirm the district court’s judgment reversing
the Commission’s decision to exclude TCC Exhibit 28 because the Commission’s decision was
contrary to its own sanctions rule and the rules of civil procedure because it was a sanction “against
TCC” even though TCC was not the offending party. I disagree.
The Commission’s rule regarding sanctions for discovery abuse expressly allows the
Commission to strike “pleadings or testimony, or both, in whole or in part” as a remedy for discovery
abuse. 16 Tex. Admin. Code § 22.161(c)(8), (d) (2007) (Pub. Util. Comm’n). The Commission’s
decision to exclude Sollosy’s testimony and expert report was not a sanction “against TCC.” Sollosy
was a witness for Commission staff, not TCC. Thus, if anything, excluding Sollosy’s testimony
was a sanction against Commission staff, not TCC. Furthermore, the record reflects that TCC
provided additional testimony from various witnesses addressing the same issues addressed by
Sollosy—namely, whether the sale of TCC’s share of the STP was a bona fide third-party sale under
a competitive offering in compliance with section 39.262(h) of the PURA, whether the price TCC
received for its share of the STP was reasonable, and whether the bundling of TCC’s Coleto Creek
plant with other facilities was commercially reasonable. This evidence demonstrates that Sollosy’s
testimony and expert report were merely cumulative. In light of the fact that Sollosy’s testimony and
expert report were cumulative of other evidence introduced by TCC, I cannot conclude that the
Commission’s decision violated its own sanctions rule, much less that the Commission abused its
discretion in striking Sollosy’s testimony and report.
For the same reasons, even if the rules of civil procedure apply to discovery in
Commission proceedings, I cannot conclude that the Commission’s decision to strike Sollosy’s
43
testimony and report was contrary to those rules. Like the Commission’s rule regarding sanctions
for discovery abuse, the rules of civil procedure give courts the discretion to exclude evidence as a
sanction for discovery abuse. See, e.g., Tex. R. Civ. P. 193.6(a), 215.2(b)(4). Because Sollosy was
a witness for Commission staff, not TCC, and his testimony and report were cumulative of other
evidence offered by TCC, I would conclude the Commission’s decision striking Sollosy’s testimony
and report comports with the rules of civil procedure and was not an abuse of discretion.25
Therefore, I would sustain the Commission’s third issue and Joint Intervenors’ eighth issue, reverse
that portion of the district court’s judgment finding that the Commission erred in striking Sollosy’s
testimony and expert report, and render judgment affirming the Commission’s decision excluding
Sollosy’s testimony and expert report.
G. PUC Treatment of TCC’s Tax Accounts
In its second issue on appeal, TCC argues that the district court erred in upholding
the Commission’s treatment of TCC’s federal tax accounts for Accumulated Deferred Investment
Tax Credits (ADITC) and Excess Deferred Federal Income Tax (EDFIT) because of the threat of
“normalization violations.”26 TCC requests this Court to reverse the district court’s judgment and
remand this issue to the Commission for further consideration. The Commission joins in this request
25
I would also reject TCC’s argument that the exclusion of TCC Exhibit 28 was harmful
error because TCC fails to address the cumulative nature of Sollosy’s testimony and expert report.
To establish harm as to the exclusion of evidence, TCC must demonstrate that the excluded evidence
was both controlling on a material issue and not cumulative of other evidence. See Williams Distrib.
Co. v. Franklin, 898 S.W.2d 816, 817 (Tex. 1995).
26
A normalization violation is essentially a violation of the tax accounting regulations of the
Internal Revenue Service. See CenterPoint, 2008 Tex. App. LEXIS 2819, at *109-10 (discussing
normalization violations).
44
asserting that federal tax law regarding normalization violations is in flux. The Joint Intervenors
dispute whether a remand to the Commission is appropriate and argue that the district court properly
rejected the request for a remand to the Commission.
This Court recently addressed a similar issue in CenterPoint. See CenterPoint,
2008 Tex. App. LEXIS 2819, at *105-18. In that case, we affirmed the Commission’s treatment of
CenterPoint’s ADITC and EDFIT accounts and the Commission’s related reductions to
CenterPoint’s stranded cost recovery, see id. at *115; however, we remanded the issue for the
Commission to consider whether it was appropriate to provide a remedy in the event that the IRS
later determined that a normalization violation had occurred. Id. at *117-18. For the same reasons
expressed in CenterPoint, I would affirm the Commission’s treatment of TCC’s ADITC and EDFIT
accounts, but I would also conclude that a remand is appropriate for the Commission to consider the
effects of the IRS’s private letter ruling issued to TCC after the close of evidence before the
Commission. Therefore, I would reverse that portion of the district court’s judgment affirming the
Commission’s decision not to consider the effects of the private letter ruling issued to TCC, and
remand this cause back to the Commission for further proceedings.
H. Capacity Auction True-up
In addition to determining TCC’s stranded costs, the legislature charged the
Commission with reconciling TCC’s capacity auction true-up award. See Tex. Util. Code Ann.
§ 39.262(d). TCC sought a capacity auction true-up award of $482,664,890, which the Commission
reduced by $420,695,372. The district court affirmed the Commission’s reduction to TCC’s
proposed capacity auction true-up award. On appeal, TCC argues that the district court’s judgment
45
should be reversed because the Commission’s reduction was “unsupported by substantial evidence,
arbitrary and capricious, grossly excessive, disproportionate to any downward bias from alleged
deficiencies in TCC’s capacity auction process, and reaches a completely unreasonable result.”
I disagree.27
To ensure the availability of power to all retail competitors in the newly deregulated
market, the legislature required each electric utility, including power generation companies, to
auction off entitlements to “at least 15 percent” of the electric utility’s installed generation capacity.
See Tex. Util. Code Ann. § 39.153(a) (emphasis added). The Commission concluded, and no one
disputes, that TCC failed to auction entitlements to at least 15% of its installed generation capacity
during 2002 and 2003. The dispute centers upon whether TCC satisfied the requirements of the
relevant “safe-harbor” provisions and, therefore, could be deemed to have met the 15% statutory
requirement or, if not, to what award, if any, TCC was entitled.
As part of the transition to a competitive retail electric market, the legislature required
each formerly bundled utility to auction off 15% of its installed generation capacity before and after
the date on which customer choice began—January 1, 2002. See Tex. Util. Code Ann. § 39.153(a),
(b). These auctions were designed to encourage retail competition by providing a source of power
to new competitors in the market. See CenterPoint, 2008 Tex. App. LEXIS 2819, at *126-27;
Reliant I, 101 S.W.3d at 137. The legislature also directed the Commission to adopt rules defining
27
TCC and the Commission had a fundamental disagreement about how to interpret the
relevant provisions in the PURA and the Commission’s rules regarding TCC’s statutory obligation
to auction capacity.
46
the scope of the capacity entitlements to be auctioned and the procedures to be followed.28 See
Tex. Util. Code Ann. § 39.153(e)-(g); 16 Tex. Admin. Code § 25.381 (2007) (Pub. Util. Comm’n).
Pursuant to the Commission’s rule, the auctions were to be held four times a year, 16 Tex. Admin.
Code § 25.381(h)(1)(A)(i), and the utilities were obligated to sell entitlements to four types
of capacity products: baseload, gas-intermediate, gas cyclic, and gas-peaking. Id. § 25.381(c)(5),
(f)-(g). The amount of each type of product to be sold varied depending on the utility’s generation
assets, but the total amount of entitlements sold had to equal at least 15% of the utility’s total
generation capacity. Id. § 25.381(e)(1).
If a utility failed to auction off at least 15% of its generation capacity, it could still
be deemed to have met this requirement if it satisfied the safe-harbor provisions established by
the Commission. The Commission established two safe-harbor provisions that are relevant to
this appeal. First, under the Commission’s capacity auction rule, a utility will be deemed to have
met the 15% requirement if it offered products in a product category and successfully sold all of
the entitlements offered in at least one month in that category. Id. § 25.381(h)(1)(B)(iv); see also
id. § 25.381(h)(7)(C).29 If there is no month in which all of the products in a given category
were sold, the company must make a proposal to the Commission to meet the 15% requirement.
16 Tex. Admin. Code § 25.381(h)(7)(C). This safe-harbor provision became part of the
Commission’s capacity auction rule in June 2002, and therefore only relates to capacity auctions
in 2003.
28
The Commission adopted PUC Substantive Rule 25.381. See 16 Tex. Admin. Code
§ 25.381 (2007) (Pub. Util. Comm’n).
29
The same safe-harbor provision appears in both of these portions of the Commission’s
capacity auction rule.
47
Second, the Commission approved a settlement in two proceedings—PUC Docket
Nos. 23774 and 24888—adopting a capacity-auction-mechanics document that included a safe-
harbor provision applicable for certain capacity auctions in 2002. The Commission determined that
this safe-harbor provision was “significantly different” than the safe-harbor provision established
in the Commission’s rule. To satisfy this safe-harbor provision, a utility must sell all of its offered
entitlements in a given month. If, in a given month, all entitlements are not sold, the utility must
propose to auction additional entitlements to the products that did sell in order to meet the 15%
requirement. This safe-harbor provision allows a utility to remedy its failure to sell sufficient
products only by offering additional entitlements for the products that did sell. In contrast, the safe-
harbor provision in the Commission’s capacity auction rule is product-specific and requires the
utility to sell all of the entitlements offered in at least one month for each product category. To
remedy a deficiency under the rule’s safe-harbor provision, the utility may propose to modify the
product’s offering price or the product category, or it may offer alternative capacity products.
In addition, the safe harbors established in Docket Nos. 23774 and 24888 have only
limited applicability. The capacity-auction-mechanics document in Docket No. 23774 applies only
to the initial auction—i.e., the September 2001 auction. The capacity-auction-mechanics document
adopted in Docket No. 24888 contains the same limiting language. Because Docket No. 24888
addressed only the mechanics of two auctions held in March 2002 and July 2002, the safe-harbor
provision from Docket No. 24888 only applies to the initial auction in 2002—i.e., the March 2002
auction.
48
1. TCC’s compliance with the 15% requirement
In its first argument on appeal, TCC contends that it should not “be required to do the
impossible—successfully sell products that the market does not want.” TCC complains that the
Commission required the auction of four specific products that were defined in minute detail at
minimum prices established by the Commission and that to construe section 39.153 of the PURA
in a manner that requires TCC to successfully sell at auction 15% of these Commission-designed,
Commission-priced products is unreasonable and leads to absurd results. Stated differently, TCC
argues that it should not be held to the 15% requirement in section 39.153 because the market did
not want the products that were to be sold at auction. In support of this argument, TCC claims that
none of the other utilities required to conduct capacity auctions were successful at selling
“unmarketable” products.
I am unpersuaded by this argument. The language in section 39.153(a) is clear
and unambiguous: it requires each utility to sell “at least 15 percent” of its generation capacity.
Tex. Util. Code Ann. § 39.153(a). Moreover, section 39.153(e) charges the Commission with
authority to define the scope of capacity entitlements to be auctioned. Id. § 39.153(e). Although this
section gives some guidance to the Commission,30 the legislature left it to the Commission’s
30
Sections 39.153(e)(1)-(5) provide that the entitlements:
(1) may be sold and purchased in periods of not less than one month nor more
than four years;
(2) may be resold to any lawful purchaser, except for a retail electric provider
affiliated with the electric utility that originally auctioned the entitlement;
(3) include no possessory interest in the unit from which the power is produced;
49
discretion to determine the types of capacity entitlements to be auctioned. Id. And TCC does not
argue that the Commission-designed products did not meet the requirements of section 39.153(e).
Rather, TCC argues that the products were “unmarketable.” TCC, perhaps recognizing the fallacy
of its own argument, dismisses it with the statement that “TCC was not required to meet
this impossible requirement because TCC satisfied the applicable ‘safe harbor provisions.’” I would
reject the notion that TCC was not required to satisfy the 15% requirement in section 39.153(a).
2. TCC’s compliance with safe-harbor provisions
In its second argument on appeal, TCC argues that safe harbors existed during both
2002 and 2003 and that TCC met the applicable safe-harbor provisions and, therefore, the
Commission should have found that TCC satisfied the 15% requirement. As part of its argument,
TCC contends that safe harbors existed for all of 2002 under the settlements adopted by the
Commission in Docket Nos. 23774 and 24888. However, as previously discussed, the settlements
adopted by the Commission in each of these dockets only applied to the initial auction addressed
in each proceeding—i.e., the September 2001 and March 2002 auctions. See discussion infra. The
Commission concluded that TCC could only be deemed to have met its capacity auction obligation
(4) include no obligations of a possessory owner of an interest in the unit from
which the power is produced; and
(5) give the purchaser the right to designate the dispatch of the entitlement,
subject to planned outages, outages beyond the control of the utility operating
the unit, and other considerations subject to the oversight of the applicable
independent organization.
Tex. Util. Code Ann. § 39.153(e)(1)-(5).
50
for 2002 if TCC met the requirements of the safe harbor for each of these two auctions.
Accordingly, the Commission considered only whether TCC complied with the safe-harbor
provisions for the September 2001 and March 2002 auctions.
Examining TCC’s sales in the September 2001 auction, the Commission found that
TCC failed to sell all of its offering in any one month covered by the September 2001 auction.31 In
light of this failure, the safe-harbor provision in Docket No. 23774 required TCC to propose to
the Commission a plan to sell all of its offering in any one month covered by the September 2001
auction. Because TCC made no such proposal and continued to offer the same number of
entitlements in its subsequent auctions, the Commission concluded that TCC failed to achieve the
safe harbor for the September 2001 auction. And the Commission likewise concluded that TCC
failed to achieve the safe harbor for capacity sold in 2002.
As for 2003, the Commission examined whether TCC met the safe harbor stated in
rule 25.381(h)(1)(B)(iv) and (h)(7)(C). The Commission determined that there was no single month
in which TCC sold all of its offered gas-intermediate or gas-peaking products. Given this failure,
the rule required TCC to propose to the Commission a plan to offer modified or different capacity
products to meet its 15% obligation. TCC did so, and proposed to offer modified versions of these
products, but even the modified products failed to sell in sufficient quantities. According to the
testimony of TCC witness Michael Isenberg, TCC sold no additional gas-intermediate entitlements
and only three of its four offered gas-peaking entitlements. TCC made no additional proposals.
31
The Commission’s finding was based on the direct testimony of TIEC witness Jeffry
Pollock.
51
Thus, the Commission concluded that TCC failed to satisfy the safe harbor established in the
Commission’s rule for capacity sold in 2003.32
Having reviewed the record, I would conclude that the Commission’s determinations
that TCC failed to satisfy the applicable safe harbor in either 2002 or 2003 was supported by
substantial evidence and was neither arbitrary nor capricious.
3. TCC’s obligation to sell one- and two-year strips
In addition to its failure to sell the amount of capacity required by the PURA and the
Commission’s rules, the Commission also determined that TCC failed to sell products over the terms
required by the Commission’s capacity auction rule. The Commission’s rule required TCC to offer
entitlements to capacity products for various time periods. Of the total number of entitlements
offered by the utility, approximately 20% must be auctioned as two one-year strips for 2002 and
2003, with the strips offered jointly. See 16 Tex. Admin. Code § 25.381(h)(3)(A)(i). An additional
30% of the entitlements must be in the form of one-year strips for 2002. Id. § 25.381(h)(3)(A)(ii).
The remainder of the utility’s offered capacity must be in the form of discrete months for 2002. Id.
§ 25.381(h)(3)(A)(iv) and (v). No one disputes that TCC failed to offer one-year or two-year strips
during its initial capacity auction. TCC witness Isenberg testified that TCC offered the equivalent
32
With respect to 2003, TCC argues that the Commission’s determination was flawed
because the Commission improperly included TCC’s mothballed plants as part of TCC’s total
generation capacity. This argument is not relevant because the record demonstrates that TCC failed
to meet its 15% obligation in 2003 regardless of whether TCC’s mothballed capacity was included
or excluded. Indeed, the record shows, and the Commission concluded, that TCC sold only 5% of
its capacity in 2003, if the mothballed capacity is included, and only 8%, if the mothballed capacity
is excluded.
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amount of capacity in terms of discrete months because, as part of the settlement resolving the AEP-
CSW merger proceeding, TCC had agreed to sell several plants constituting 1354 MW of capacity.
TCC contended that its capacity auction notices stated that it was not offering strips and that neither
the Commission nor any other party objected. TCC argued that the lack of an objection excused any
failure to offer the strips. The Commission concluded that TCC’s failure to offer the strips violated
the capacity auction rule and was not excused by TCC’s statements in the auction notices that it
would not be offering the strips because the capacity auction rule plainly states that what is deemed
approved in the event that no objection is made to the notice is the notice itself, not the substantive
details of the auction. See id. § 25.381(h)(2)(B)(I).
TCC makes this same argument on appeal and argues that the very purpose of the
notice is to provide the substantive details, not simply to provide notice without content. Even if one
accepts TCC’s argument, that would not excuse TCC’s failure to meet the 15% requirement, much
less its failure to satisfy the applicable safe harbor for 2002 or 2003. Therefore, it is irrelevant for
purposes of this appeal whether the lack of objection to TCC’s notices excused its failure to offer
the yearly strips or not.
4. Calculation of TCC’s capacity auction true-up award
The Commission concluded that TCC capacity auctions fell substantially short of
TCC’s obligations under the PURA and the Commission’s capacity auction rule. Specifically, TCC
failed to sell 15% of its generation capacity as required in section 39.153; TCC failed to achieve safe
harbor in either 2002 or 2003; and TCC failed to offer approximately half of its capacity entitlements
in the form of yearly strips as required by rule 25.381. These defects in TCC’s capacity auctions
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required the Commission to determine an alternative proxy for the capacity auction price to be used
in the capacity auction true-up formula stated in the Commission’s rule.
(A) Commission authority to develop an alternative calculation method
This Court considered a utility’s failure to comply with the statutory capacity auction
requirements in CenterPoint. See CenterPoint, 2008 Tex. App. LEXIS 2819, at *126-61. In
that case, we reversed the district court’s judgment and affirmed the Commission’s final order
disallowing $440 million of CenterPoint’s requested capacity auction true-up award. Id. at *24,
*160-61, *196. Like TCC, CenterPoint had failed to comply with the statutory requirements
to auction 15% of its generation capacity and likewise failed to satisfy the applicable safe-harbor
provisions. See id. at *126-161. This Court held that, in light of CenterPoint’s failures,
the Commission acted within its authority when it used an alternative method for establishing
the capacity auction price to calculate CenterPoint’s capacity auction true-up award. Id. at *126-61,
*196.
TCC presents the same arguments this Court rejected in CenterPoint. First, as
previously discussed, TCC argues that it should not be held to the 15% obligation because there was
simply no market for the products designed and priced by the Commission to be sold at auction. In
other words, TCC argues that the failure to satisfy the 15% requirement was due to factors outside
of its control. This Court rejected the same argument in CenterPoint, finding that by specifying what
products were to be sold and for what amount, the Commission was doing exactly as the legislature
had instructed it to do. Id. at *150-52; see also Tex. Util. Code Ann. § 39.153(e) (requiring the
Commission to determine the scope of entitlements to be offered and the minimum amount of
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capacity to be auctioned), (f) (requiring the Commission to establish procedures for the auctions,
including designating which generation units are offered and establishing an opening bid price).
Moreover, the Court recognized that, although CenterPoint expressed dissatisfaction with the
Commission’s actions on appeal, CenterPoint had failed to challenge the products or the price
specified in the Commission’s capacity auction rule within the time period authorized by statute.
See CenterPoint, 2008 Tex. App. LEXIS 2819, at *151-52 (citing Tex. Util. Code Ann. § 39.001(f)).
Like CenterPoint, TCC has failed to show that it objected to the products or the price specified in
the Commission’s rule. For the same reasons expressed by this Court in CenterPoint, I would reject
TCC’s argument that its failure to satisfy the 15% requirement was due to factors beyond its control.
Second, TCC argues that any reduction to its proposed capacity auction true-up award
was improper because TCC substantially complied with the applicable safe-harbor provisions.
Again, the Court rejected this argument in CenterPoint. See id. at *145-49. The Court explained
that the legislative goal of the capacity auction was to have each utility auction at least 15% of its
generation capacity. Id. at *146-47. Moreover, the legislature’s use of the phrase “at least” was
some indication that the legislature thought 15% was the absolute minimum amount of capacity
that needed to be sold in order to determine an accurate estimate of the capacity auction price. Id.
at *147. Thus, the Court concluded that substantial compliance must ultimately be measured
by comparison to this legislative goal, and not the Commission’s safe-harbor rule. Id. Indeed, by
establishing a safe-harbor provision, the Commission essentially determined what is necessary to
establish substantial compliance with the legislative goal. Id. at *148. For the reasons expressed
in CenterPoint, I would conclude that TCC failed to substantially comply with the relevant
requirements. See id.
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Finally, TCC argues that the Commission’s reduction to TCC’s proposed capacity
auction award was excessive when compared to what TCC considers to be minor deficiencies in its
capacity auctions. TCC essentially argues that the PUC could have used simple mathematical
calculations to determine “what would have happened” in TCC’s auctions in the absence of any
deficiencies and that it was improper for the Commission to develop an alternative method for
determining the “capacity auction price” to be used in the true-up formula when calculating TCC’s
capacity auction true-up award. Although, in CenterPoint, we found the framing of this argument
compelling, this Court rejected CenterPoint’s characterization of the reduction. Id. at *155. The
Court explained that the situation presented in this issue was similar to the one presented in the
market valuation of CenterPoint’s generation assets. Id. Because the relevant statutory provisions
and the Commission’s rule assume the utility will comply with either the 15% requirement or with
the safe harbor, neither one addresses the possibility of noncompliance. Id. The Court concluded
that the Commission was caught between a statutory mandate requiring utilities be allowed to
recover for their capacity auction costs and the utility’s noncompliance with the requirements
necessary to determine an accurate award. Id. Accordingly, in the absence of compliance, the Court
found the Commission had the implied authority to develop an alternative method for determining
the capacity auction price to be used in calculating CenterPoint’s true-up award. Id. at *156. For
the same reasons, I would conclude that the Commission had the implied authority to develop an
alternative method for determining the capacity auction price to be used in calculating TCC’s
capacity auction true-up award. It is therefore necessary to consider whether the Commission’s
decision was supported by substantial evidence.
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(B) Was the Commission’s calculation supported by substantial evidence?
In its final order, the Commission considered various proxies proposed by the parties
for use as the capacity auction price. TCC argued that the capacity price obtained in its auction
should be used but, if the Commission determined a disallowance was appropriate, it should
only make narrow adjustments to address the specific deficiencies of TCC’s capacity auctions.
Alternatively, TCC proposed that the Commission use the Megawatt Daily ERCOT South Zone
index to establish a proxy for TCC’s capacity auction price. According to TCC, use of this index
would produce prices of $25.76/MWh for 2002 and $39.60/MWh for 2003, and would reduce TCC’s
proposed capacity auction true-up award by approximately $90 million. In contrast, the intervenors
argued that the proper adjustment was derived by use of TCC’s actual capacity and energy sales
revenues for 2002 and 2003. Under this approach, TIEC determined that the appropriate prices
would be $42.50/MWh for 2002 and $48.01/MWh for 2003. The Commission adopted the approach
and the proposed prices based on TCC’s actual revenues for 2002 and 2003 as urged by
the intervenors.
TCC argues that the prices adopted by the Commission are not supported by
substantial evidence because there is no evidence that these prices represent competitive prices.
TCC contends that these prices were not competitive because the evidence showed that they were
based primarily on non-market revenues such as resource-must-run (RMR) contracts and sales to
TCC’s affiliated retail electric provider. I disagree.
The purpose of the capacity auctions as stated in the statute was to compare the actual
prices received at auction with the prices in the 2001 ECOM model and award the difference to
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the utility. See Tex. Util. Code Ann. § 39.262(d)(2). Because the Commission determined
and the record supports that TCC’s capacity auction was deficient in many respects, the Commission
was unable to make the statutory comparison because it did not have actual prices received by
TCC in the capacity auctions. Accordingly, the Commission was left to develop an alternative
method for determining the prices that TCC would have received if it had performed a successful
capacity auction.
This Court addressed a similar situation in CenterPoint. See CenterPoint, 2008 Tex.
App. LEXIS 2819, at *137-38. Like TCC, CenterPoint also failed to comply with the statutory
requirement to auction 15% of its generation capacity. Id. Having performed a deficient capacity
auction, the Commission could not use the prices obtained by CenterPoint in the capacity auctions
to determine the capacity auction true-up. Id. As a result, the Commission developed a proxy for
the capacity auction price by using the average price of all capacity products sold by CenterPoint.
Id. This Court concluded there was a reasonable basis for the Commission’s decision to use a proxy
for CenterPoint’s capacity auction price and that the Commission’s decision was consistent with the
relevant statutory provisions. Id. at *156-60. This Court affirmed the Commission’s calculation of
CenterPoint’s capacity auction true-up award. Id. at *160.
Here, as in CenterPoint, the Commission used the average price of all TCC capacity
sales during the relevant time period to determine the proxy for TCC’s capacity auction price. This
was the approach urged by TIEC, the Cities, and OPC. TIEC witness Jeffry Pollock testified that
using the average price of all of TCC’s capacity sales during the relevant time period would produce
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prices of $42.50/MWh for 2002 and $48.01/MWh for 2003. Cities witness Scott Norwood33 and
OPC witness Randall Falkenberg also testified to this approach and calculated price figures that were
very close to or identical to these prices.
The Commission adopted the approach urged by the intervenors and agreed that using
the average price of all capacity sales was consistent with the purpose of the capacity auction true-up
to reconcile the utility’s actual results in the competitive market with the power price projections
from the 2001 ECOM model. The Commission recognized that the problems with TCC’s capacity
auction were substantial and were more significant than those identified by the Commission in
CenterPoint’s capacity auction. In particular, the Commission found that, by failing to sell sufficient
quantities of products other than baseload, the results of TCC’s capacity auctions over-represented
the lower baseload pricing and were, therefore, distorted downwards. The Commission further
concluded that the approach urged by the intervenors was consistent with the approach the
Commission took in the CenterPoint true-up and rejected TCC’s proposal to correct the deficiencies
in TCC’s capacity auction on a “flaw-by-flaw” or “piecemeal” basis.
Consistent with this Court’s opinion in CenterPoint, I would conclude that there is
a reasonable basis in the record to support the Commission’s development of an alternative method
for determining TCC’s capacity auction price. The simple fact that the Commission chose to use the
33
To the extent TCC complains that Norwood admitted that TCC’s revenues were
“dominated” by what TCC alleges are non-competitive sales, TCC takes one statement from
Norwood’s entire testimony out of context. The full record of Norwood’s testimony supports the
approach urged by the intervenors. Moreover, the Commission was entitled to accept or reject any
part or all of each expert’s testimony. City of Corpus Christi v. Public Util. Comm’n, 188 S.W.3d
681, 695 (Tex. App.—Austin 2005, pet. denied); Central Power & Light Co. v. Public Util. Comm’n,
36 S.W.3d 547, 561 (Tex. App.—Austin 2000, pet. denied).
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method urged by the intervenors instead of that urged by TCC does not make the Commisison’s
decision unreasonable. The method chosen by the Commission was reasonable and consistent with
the relevant statutory provisions, and I would conclude that the Commission’s decision and
calculation of TCC’s capacity auction true-up award was supported by substantial evidence. I would
overrule TCC’s first issue.
In a related issue, the Joint Intervenors assert that the district court erred by affirming
the Commission’s decision to include interest on TCC’s capacity auction true-up award. The
Commission determined that including interest on TCC’s capacity auction true-up was necessary to
make the utility whole and was also consistent with the supreme court’s decision in CenterPoint
Energy, 143 S.W.3d at 85. As recognized by the supreme court in CenterPoint Energy, the purpose
of the capacity auction true-up was to ensure that the utility earned the same margins that were
projected in the 2001 ECOM model. TCC was entitled to a capacity auction award because it did
not recover all of the predicted margins. Moreover, since those amounts will not be recovered until
the true-up is complete, it necessarily follows that a time value for the delay must be added to make
the utility whole. See id. This is likewise consistent with this Court’s decision in Centerpoint. See
2008 Tex. App. LEXIS 2819, at *161-70. Accordingly, for the reasons expressed in this Court’s
CenterPoint opinion, I would overrule Joint Intervenors’ issue nine.
III. Conclusion
Having considered all of the parties’ issues raised on appeal, I would affirm the
district court’s judgment in part, reverse in part, and remand this cause to the Commission for further
proceedings. Because the plain language of section 39.252(d) does not preclude the Commission’s
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adjustments to the net book value of TCC’s generation assets for commercial unreasonableness
related to the sales of TCC’s share in the STP and the decision to bundle the Coleto Creek Coal Plant
with other generation assets, I dissent from the majority’s conclusion that it does. I would reverse
the district court’s judgment on this point and affirm the Commission’s reductions to net book value.
__________________________________________
Jan P. Patterson, Justice
Before Justices Patterson, Puryear and Pemberton;
Joined in part by Justices Puryear and Pemberton
Filed: May 23, 2008
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