# CenterPoint Energy Houston Electric, LLC v. Gulf Coast Coalition of Cities

> Texas Court of Appeals, 3rd District (Austin) · April 17, 2008 · 252 S.W.3d 1

URL: https://www.frixlaw.com/law-library/cases/1384317

## Case

- **Full name:** CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC and Texas Genco, LP, Appellants, Gulf Coast Coalition of Cities, Houston Council for Health and Education, City of Houston, Coalition of Cities, State of Texas, Office of Public Utility Counsel, Public Utility Counsel, and Texas Industrial Energy Consumers, Cross Appellants, v. GULF COAST COALITION OF CITIES, Houston Council for Health and Education, City of Houston, Coalition of Cities, State of Texas, Office of Public Utility Counsel, Public Utility Counsel, Texas Industrial Energy Consumers, Occidental Power Marketing, LP, and Coalition of Commercial Ratepayers, Appellees, Office of Public Utility Counsel, Public Utility Counsel, CenterPoint Energy Houston Electric, LLC, Texas Genco, LP, and Reliant Energy Services, LLC, Cross-Appellees
- **Court:** Texas Court of Appeals, 3rd District (Austin)
- **Decided:** April 17, 2008
- **Citations:** 252 S.W.3d 1; 2008 Tex. App. LEXIS 2819; 2008 WL 1753556
- **Precedential status:** Published
- **Opinion:** Opinion by Puryear
- **Judges:** Law, Puryear, Henson
- **Cited by:** 61 later opinions in the Frix Law Library

## Citator (automated)

- **Red flag:** Reversed in part by State v. Public Utility Com'n of Texas, 54 Tex. Sup. Ct. J. 690 (2011).
- Negative treatments: 1
- Distinguished by: 0
- Full citator and citing cases: https://www.frixlaw.com/law-library/cases/1384317

## How later opinions describe it (automated extraction)

- recognizing that except as provided by statute, only when “there is a ruling on the merits of the claims may a losing party appeal” from the denial of a writ of habeas corpus
- describing statutory framework for transition to competitive retail electric market
- describing transition from regulated to deregulated market

## Opinion text

OPINION
DAVID PURYEAR, Justice.
Our opinion and judgment issued on December 20, 2007, are withdrawn, and the following opinion is substituted.
This appeal concerns the transition of Texas’s energy industry from a regulated market to a competitive one. When it approved the switch to a competitive market, the legislature contemplated the possibility that the switch might saddle formerly regulated utilities with costs that they would have recovered under regulation but would be unable to recover in a competitive market. As a result, the legislature enacted statutes authorizing utilities to recover these costs in proceedings called true-up proceedings held before the Public Utility Commission (the “Commission”).
The utilities involved in this case estimated the costs that they would not be able to recover due to deregulation and filed an application with the Commission seeking recovery for those costs. However, the Commission determined that not all of the relevant requirements had been satisfied when the utilities made their calculations and, therefore, performed its own estimate of the utilities’ unrecovered costs. The total amount determined by the Commission was less than the amount that the utilities originally requested. In addition to producing its own estimation, the Commission also made several reductions to the utilities’ recovery. Although the Commission allowed the utilities to recover for various construction projects that they had started, it deducted the value of certain tax benefits given to the utilities. The Commission also reduced the utilities’ recovery because it concluded that the utilities had recovered some of their costs through other means. Finally, although the Commission allowed the utilities to recover the requested amount for credits that the Commission had previously ordered them to give to their customers, it denied recovery for interest on the credits.
The district court affirmed the majority of the Commission’s order but reversed the order and increased the utilities’ recovery in two respects. First, the district court concluded that the utilities should
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recover for the interest on the credits that they were ordered to give. Second, the district court concluded that the Commission’s decision to undertake its own estimate of one of the utilities’ costs was inappropriate and further concluded that the utilities should recover the amount originally requested.
We will affirm the judgment of the district court in part and reverse and remand in part.
STATUTORY FRAMEWORK
To give context to the merits of this case, we will describe the statutory framework governing this case. This appeal concerns the utility market’s transition from a regulated industry to a competitive, deregulated market.
See
Tex. Util.Code Ann. §§ 39.001-.910 (West 2007). Prior to deregulation, utilities operated as monopolies but were regulated by the Commission and were “prohibited from charging monopoly prices.”
Reliant Energy, Inc. v. Public Util. Comm’n,
101 S.W.3d 129, 133 (Tex.App.-Austin 2003)
(“Reliant
I”),
rev’d in part sub nom., CenterPoint Energy, Inc. v. Public Util. Comm’n,
143 S.W.3d 81 (Tex.2004);
see Reliant Energy, Inc. v. Public Util. Comm’n,
153 S.W.3d 174, 182 (Tex.App.-Austin 2004, pet. denied)
(“Reliant II”
). “[Ejach region of the state was served by a single vertically integrated utility,”
Cities of Corpus Christi v. Public Util. Comm’n,
188 S.W.3d 681, 684 (Tex.App.-Austin 2005, pet. filed), which meant that the utility “produced, transported, and retailed electricity” for the region,
Reliant I,
101 S.W.3d at 133 .
In 1999, the legislature enacted statutes that initiated the transition to a competitive retail-service industry.
See
Act of May 27, 1999, 76th Leg., R.S., ch. 405, 1999 Tex. Gen. Laws 2543 (current version at Tex. Util.Code Ann. §§ 39.001-.910). The legislature concluded that the “production and sale of electricity” was not an undertaking necessitating the utilization of monopolies or the “regulation of rates, operations, and services” and that it was in the public interest to allow customer choice and competition to determine the prices for these services. Tex. Util.Code Ann. § 39.001(a);
see also In re TXU Elec. Co.,
67 S.W.3d 130, 132 (Tex.2001) (Phillips, C.J., concurring). Accordingly, the utilities code was amended to allow for retail competition starting January 1, 2002, and to protect the interests of the citizens of Texas during the transition. Tex. Util. Code Ann. § 39.001 (a);
see also In re TXU Elec. Co.,
67 S.W.3d at 132 (Phillips, C.J., concurring).
The transition to a competitive retail market involved several changes to how utilities provided electricity. Significantly, the formerly integrated utilities were required to “unbundle” and divide into three separate entities: (1) retail electric providers, (2) power-generation companies, and (3) transmission-and-distribution utilities. Tex. Util.Code Ann. § 39.051(a)-(b);
see also In re TXU Elec. Co.,
67 S.W.3d at 132 (Phillips, C.J., concurring);
Reliant II,
153 S.W.3d at 182 . Starting in 2002, the unbundled power-generation companies owned and operated “the generating plants,”
In re TXU Elec. Co.,
67 S.W.3d at 132 (Phillips, C.J., concurring), and provided “wholesale generation services in competition with other generators entering the market,”
Cities of Corpus Christi,
188 S.W.3d at 684 . The transmission-and-distribution utilities owned and maintained “the ‘wires’ used to transport electricity from the power generation companies to all [retail electric providers] and retail consumers in the utility’s geographic area.”
Id.
at 685 . The retail electric provider sold “electricity to end-use customers” and provided “customer service.”
In re TXU Elec. Co.,
67 S.W.3d at 132 (Phillips, C.J.,
*8
concurring). In addition, new electricity providers were allowed to begin competing with the retail electric providers associated with the former integrated utilities.
See
Tex. Util.Code Ann. § 39.102(a)-(b).
After the deregulation process was completed, the power-generation and retail electric markets would be subject to the “normal forces of competition” and “customer choices,” but the transmission-and-distribution utilities would remain regulated by the Commission.
Id.
§ 39.001(a);
see Cities of Corpus Christi,
188 S.W.3d at 685 . However, the deregulation process is lengthy, and the Commission retained partial regulatory powers over power generation and the sale of electricity after January 2002.
See, e.g.,
Tex. Util.Code Ann. § 39.202 (allowing Commission some control over prices charged by utilities). During the transition, affiliated retail electric providers were required to charge a “price to beat” rate to their residential and small-business customers.
1
Id.
Prior to deregulation, utilities were allowed to recover from their customers the prudent costs they incurred when acquiring power-generation assets.
Reliant II,
153 S.W.3d at 183 n. 5;
Reliant I,
101 S.W.3d at 134 . The Commission allowed the utilities to recover these costs over time by incorporating the costs into the rates that it approved.
Reliant II,
153 S.W.3d at 183 n. 5;
Reliant I,
101 S.W.3d at 134 . As a result, utilities made significant investments in generation-related assets with the expectation of eventually recovering their costs.
See Cities of Corpus Christi,
188 S.W.3d at 685 .
Recognizing that this type of reimbursement would not occur under deregulation, utilities expressed their concern that under deregulation they would be unable to recover the costs for their investments because competition would drive the rates too low.
Reliant II,
153 S.W.3d at 183 n. 5;
Reliant I,
101 S.W.3d at 134 .
2
Because new utilities entering the market would not have “embedded generation-related costs,” they could set prices below the “level at which incumbent utilities could recover their investments.”
Cities of Corpus Christi,
188 S.W.3d at 685 .
3
Therefore, the incumbent utilities would either have to charge rates that were not competitive or absorb the added expense.
Id.
To prevent the possibility that utilities would have to absorb the costs, the legislature provided a method by which a utility could recover its “stranded costs” or those costs representing the “portion of the net book value of [the] utility’s generation assets not yet recovered through depreciation that has become unrecoverable in a deregulated market.”
Reliant I,
101 S.W.3d at 134 ;
see also
Tex. Util.Code Ann. §§ 39.001(b)(2) (finding that it is in public interest to “allow utilities with uneconomic generation-related assets ... to recover these reasonable excess costs over
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market of those assets”), .251(3) (defining generation assets as “all assets associated with the production of electricity, including generation plants”), .251(4) (defining market value as “the value the assets would have if bought and sold in a bona fide third-party transaction or transactions on the open market”), .251(7) (defining stranded costs as “the positive excess of the net book value of generation assets over the market value of the assets”),
4
.252 (providing that utility is entitled to recover stranded costs); 16 Tex. Admin. Code § 25.263 (g) (2007) (specifying what constitutes “net book value”).
Although the legislature allowed a utility to recover stranded costs, there were express limitations imposed on this right. The utility was required to mitigate the amount of stranded costs it incurs from purchasing electricity and “providing electric generation service,” Tex. UtiLCode Ann. § 39.252(a), and was required to “pursue commercially reasonable means to reduce its potential stranded costs,”
id.
§ 39.252(d). In addition, the Commission was authorized to consider “the utility’s efforts [to reduce its potential stranded costs] when determining the amount of the utility’s stranded costs.”
Id.; see also
16 Tex. Admin. Code § 25.263 (e)(4) (2007) (stating that Commission may adjust net book value of affiliated power-generation company’s generation assets if utility has failed to undertake reasonable actions to reduce its potential stranded costs);
Reliant I,
101 S.W.3d at 149 (noting that terms of section 39.252 impliedly contemplate allowing adjustments to book value, which is the only other component of stranded costs besides market value). Finally, the utilities code specifies that “[a]n electric utility, together with its affiliated retail electric provider and its affiliated transmission- and-distribution utility, may not be permitted to overrecover stranded costs.” Tex. Util.Code Ann. § 39.262(a).
To foster the recovery of stranded costs, the Commission used a computer model called the “Excess Cost Over Market” model (“ECOM”) to predict whether utilities would actually incur stranded costs in a deregulated market.
See In re TXU Elec. Co.,
67 S.W.3d at 160 (Hecht, J., dissenting). The model accounted for various factors, including fuel costs, in its calculations.
Cities of Corpus Christi,
188 S.W.3d at 686 . Based on this model, the Commission prepared a report for the Texas Senate in 1998 that predicted the amount of stranded costs that utilities would likely incur in the deregulated market (“1998 ECOM Report”).
Reliant I,
101 S.W.3d at 134 n. 3. However, in its report, the Commission did caution that the amount predicted was only an estimate and that the amount of stranded costs that would actually result, if any, might be significantly different than the estimated amount.
In re TXU Elec. Co.,
67 S.W.3d at 160 (Hecht, J., dissenting).
To minimize the impact on consumers and utilities, the legislature devised a
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three-step program for the recovery of stranded costs. The first step began in September 1999 and ended December 31, 2001. During this step, the retail electric rates charged by utilities were frozen. Tex. Util.Code Ann. § 39.052. In addition, the Legislature provided various methods for utilities to “mitigate” their stranded costs in order to lessen the impact on consumers resulting from stranded-cost recovery and to minimize the delay in the benefits resulting from competition.
Id.
§§ 39.254, .256;
5
see also In re TXU Elec. Co.,
67 S.W.3d at 160-61 (Hecht, J., dissenting). For example, to mitigate their stranded costs, utilities could transfer depreciation away from transmission-and-distribution assets to generation assets. Tex. Util.Code Ann. § 39.256.
The second step began on the first day of competition, January 1, 2002, and ended December 31, 2003.
See id.
§§ 39.001(b)(1), .201(a), (b)(3), (g), (h);
In re TXU Elec. Co.,
67 S.W.3d at 133 (Phillips, C.J., concurring). During this stage, company-specific updates were inputted into the ECOM model to ascertain the status of stranded-cost recovery.
See
Tex. Util.Code Ann. § 39.201(h);
Cities of Corpus Christi,
188 S.W.3d at 686 . If the ECOM model calculations predicted that utilities would have stranded costs even after employing the various mitigation techniques available in the first stage, the Commission was authorized to set a non-bypassable “competition transition charge” to allow the utilities to recover these costs by collecting a fee from each customer obtaining power.
See
Tex. Util.Code Ann. § 39.201(b)(3);
In re TXU Elec. Co.,
67 S.W.3d at 133 (Phillips, C.J., concurring);
Cities of Corpus Christi,
188 S.W.3d at 686-87 . This charge was intended to make up the difference between the book value and the market value of a power-generation plant and, therefore, allow utilities to recover the additional expected stranded costs.
In re TXU Elec. Co.,
67 S.W.3d at 133 (Phillips, C.J., concurring). The affiliated power-generation companies and providers would bill the charge to the transmission-and-distribution utilities, which were allowed to pass through the charge “to retail customers” by including the amount of the charge in their “ ‘wholesale’ rates.”
Id.
at 160 (Hecht, J., dissenting). The charge constituted one of a number of “nonbypassable delivery charges” passed through to customers. Tex. Util.Code Ann. § 39.201(b).
When the stranded-cost estimates were updated, the estimates “unexpectedly reflected that the utilities would have no stranded costs.”
Reliant I,
101 S.W.3d at 135 . As a result, the Commission ordered utilities to cease stranded cost mitigation efforts, “to reassign the depreciation transferred from transmission and distribution assets back to those assets, and to return monthly ‘excess mitigation credits’ to retail providers.”
Id.; see In re TXU Elec. Co.,
67 S.W.3d at 161 (Hecht, J., dissenting).
The third step began in 2004 and is the step relevant in this appeal. Tex. Util. Code Ann. §§ 39.201 , .262(c). During this stage, the Commission was required to conduct a “true-up proceeding” to determine a final calculation of a utility’s stranded costs, if any.
Id.
§§ 39.201(l),
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.262(c). The purpose of the proceeding was to reconcile the actual stranded costs incurred with the previous estimates made by the Commission.
See id.
§§ 39.201(l), .262(c);
see also
16 Tex. Admin. Code § 25.263 (a) (2007) (specifying purpose of true-up proceeding). As part of the proceeding, “each transmission and distribution utility, its affiliated electric provider, and its affiliated power generation company” were required to “jointly” file finalized stranded costs and reconcile those costs with the estimated stranded costs. Tex. Util.Code Ann. § 39.262(c).
One of the most important aspects of the true-up proceeding was the determination of the actual “market value of a utility’s generation assets.”
Reliant I,
101 S.W.3d at 143 . The code lists several alternative methods by which an affiliated power-generation company could calculate the market value of its generation assets for the purpose of calculating its stranded costs. Tex. Util.Code Ann. § 39.262(h)(1)-(4). These valuations utilize “stock prices and anticipated income streams in a competitive market.”
Cities of Corpus Christi,
188 S.W.3d at 687 (citing Tex. Util.Code Ann. §§ 39.201(l), .262(h), (i)).
The true-up calculation obtained was the “final, controlling calculation of each utility’s stranded costs.”
Id.
at 692. The utility’s actual stranded costs were determined by subtracting the actual market value of the utility’s generation assets from the book value of those assets. Tex. Util. Code Ann. §§ 39.251 (7), .252(a), .262(c), (h), (i). If the number obtained in this calculation was a positive number, then the utility was entitled to recover that amount in stranded costs.
6
Reliant I,
101 S.W.3d at 136 .
The stranded-cost true-up was only one of several true-up calculations that had to be performed as part of the transition to competition.
See
Tex. Util.Code Ann. § 39.262(d)-(g). The utilities code establishes “two parallel true-up tracks — one for stranded costs and one for the several other true-up items.”
Reliant I,
101 S.W.3d at 141 . These non-stranded-cost calculations also can “result in either credits or bills to the transmission and distribution utility from its affiliated power generation company or retail electric provider.”
Id.
at 136 (citing Tex. Util.Code Ann. § 39.262(d)-(g)).
One of the non-stranded-cost true-ups relevant to this case involves the calculation of a utility’s “capacity-auction award.” As part of the transition to a competitive market, utilities were required to auction off entitlements to some of their generation assets.
See
Tex. Util.Code Ann. § 39.153(a). The capacity-auction award constituted the difference between the price that a utility was predicted by the ECOM model to obtain for selling its power in the wholesale market during the second step of deregulation and the price actually obtained at auction during the first years of deregulation.
See
16 Tex. Admin. Code § 25.263 (i), (l) (2007). After determining the capacity-auction award, the figure was netted with another true-up award called the final fuel balance.
7
Tex. Util.Code Ann. § 39.262(d).
*12
Once the various calculations were made, they were all considered when determining whether a utility was entitled to recover for costs.
See
16 Tex. Admin. Code § 25.263 (l)(1) (2007). If the true-up balance was positive and greater than the projected costs, the utility was entitled to recover the amount calculated. Based on the actual stranded costs calculated, the Commission was authorized to alter the period of time during which a utility may collect the competition transition charge or alter the amount of the charge. Tex. Util. Code Ann. §§ 39.201 (l), -262(c), (d)(1), (g); 16 Tex. Admin. Code § 25.263 (l)(2)(A) (2007);
Reliant I,
101 S.W.3d at 137 ;
see also
Tex. Util.Code Ann. § 39.201(b) (specifying nonbypassable delivery charges).
BACKGROUND
CenterPoint Energy Houston Electric, LLC (“CenterPoint”); Reliant Energy Retail Services, LLC (“Reliant”); and Texas Genco, LP (“Genco”) (cumulatively “Joint Applicants”)
8
are the unbundled components of the formerly integrated Reliant Energy: CenterPoint is the transmission- and-distribution utility, Reliant is the affiliated retail electric provider, and Genco is the power-generation company. In March 2004, they filed a joint application for a final true-up proceeding to determine their recovery for stranded costs and non-stranded costs, including their capacity-auction award.
See
Tex. Util.Code Ann. §§ 39.252(a), .262(c), (d)(2).
In addition to the Joint Applicants, several other parties also intervened in the true-up proceeding. The intervening parties were the Office of Public Utility Counsel (“Utility Counsel”),
see
Tex. Util.Code Ann. § 13.003 (West 2007) (describing powers and duties of Utility Counsel), and several coalitions of interested parties that either were within CenterPoint’s service area or purchased energy from Center-Point, including the City of Houston, the Coalition of Cities, the Gulf Coast Coalition of Cities, the Houston Council for Health and Education, the State of Texas, and Texas Industrial Energy Consumers. For the sake of clarity, we will refer to these coalitions as the “Customers.”
Stranded Costs
In their application, the Joint Applicants asserted that they were entitled to $2,454 billion in stranded costs and $539.4 million in interest on the stranded-cost award. For ease of discussion, we will only list the specific stranded costs requested that are relevant to this appeal. First, the Joint Applicants requested $470 million in recovery for credits that the Commission had previously ordered them to give to their customers and $180 million in interest on those credits. Second, the Joint Applicants sought $147 million for various construction projects that they had begun pri- or to deregulation and for various land purchases that they made to secure locations for future power plants.
After conducting a hearing, the Commission issued its final true-up order in December 2004. In its order, the Commission authorized the recovery of the $470 million that had been awarded as credits and also allowed the Joint Applicants to recover the $147 million spent on pre-deregulation construction projects. However, the Commission made significant reductions to the Joint Applicants’ requested recovery. First, it disallowed recovery for the $180 million in interest that had been credited to the utilities’ customers. Sec
*13
ond, the Commission reduced the award by $146 million to account for various tax benefits given to the Joint Applicants. Finally, because the Commission believed that the Joint Applicants recovered some of their stranded costs through the capacity-auction process, the Commission further reduced the stranded-cost true-up award by $378.4 million.
In its order, the Commission also made two alternative holdings regarding the Joint Applicants’ estimate of the value of their generation assets, which they were required to calculate as part of the recovery process. Under its primary holding, the Commission concluded that the Joint Applicants’ valuation of their assets was not valid because they did not comply with all the statutory requirements. For this reason, the Commission performed its own valuation of the Joint Applicants’ assets.
See
Tex. Pub. Util. Comm’n,
Application of CenterPoint Energy Houston LLC, Reliant Energy Retail Services LLC, and Texas Genco LP to Determine Stranded Costs and Other True-Up Balances Pursuant to PURA § 39.262,
Docket No. 29526, at 18 (Dec. 17, 2004) (Order on Rehearing) (“order”). In its appraisal, the Commission concluded that the market value of the assets was approximately $509 million higher than that estimated by the Joint Applicants. Consequently, the Commission determined that the Joint Applicants’ stranded costs were less than the amount requested and reduced their recovery accordingly. After making the reductions previously discussed and after utilizing its own market valuation, the Commission concluded that the Joint Applicants were entitled to recover $1,222 billion in stranded costs and $121 million in interest under its primary holding.
Under its alternative holding, the Commission assumed that the Joint Applicants satisfied the necessary statutory requirements but made an additional reduction to the Joint Applicants’ recovery that it didn’t make in its primary holding. The Commission deducted approximately $508 million from the Joint Applicants’ recovery to account for business practices that the Commission believed were commercially unreasonable and for the tax benefit resulting from this unreasonable behavior. After making all the relevant reductions, the Commission concluded that the Joint Applicants were entitled to recover $945 million in stranded costs plus $68 million in interest under its alternative holding.
The chart below details the relevant stranded-cost recovery requested by the Joint Applicants and the various modifications made by the Commission in its primary and alternative holdings:
Stranded Costs Calculations in Millions of Dollars
9
[[Image here]]
*14
[[Image here]]
Capacity Auction
In their application, the Joint Applicants also requested $1,357 billion for deficits sustained from the capacity auctions. However, in its order, the Commission reduced the requested award. The Commission concluded that the capacity-auction calculation performed by the Joint Applicants was invalid because they failed to satisfy the necessary statutory requirements.
See
Tex. Util.Code Ann. §§ 39.153, .262(d)(2). As with the asset valuation, the Commission performed its own estimate of the capacity-auction award and deducted $440 million from the Joint Applicants’ requested recovery. Although the Commission reduced the requested award, it did allow the Joint Applicants to recover $168 million in interest on the award to account for the fact that the Joint Applicants had been deprived of the predicted capacity-auction award for a specific period of time.
The chart below details the relevant capacity-auction recovery requested by the Joint Applicants and the various modifications made by the Commission in its primary and alternative holdings:
Capacity Auction Calculations in Millions of Dollars
[[Image here]]
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[[Image here]]
Joint Applicants’ Appeal
After the order was issued, the Joint Applicants appealed the decision to the district court.
See
Tex. Util.Code Ann. § 15.001 (West 2007) (stating that party to proceeding before Commission is entitled to judicial review). The Customers and the Utility Counsel also appealed the order, contending that the Commission erred in several respects.
After reviewing the Commission’s order, the district court issued its judgment. The district court affirmed the majority of the Commission’s order, including the decision of the Commission to perform its own assessment of the value of Joint Applicants’ assets, but reversed on two grounds. The district court’s reversal increased the amount of stranded costs that the Joint Applicants were entitled to receive. Specifically, the judgment concluded that the Commission erred by (1) preventing the joint applicants from collecting $180 million in interest on the credits and (2) disallowing $440 million from the capacity-auction true-up. Accordingly, the Joint Applicants’ recovery was increased by those amounts.
The Joint Applicants, the Customers, the Utility Counsel, and the Commission all appeal the judgment of the district court.
See id.
§§ 15.001 (stating that any party to Commission proceeding may appeal), 39.262(j) (specifying that final order by Commission is subject to judicial review); Tex. Gov’t Code Ann. § 2001.171 (West 2000) (explaining that after exhausting administrative remedies, party aggrieved by final agency decision is entitled to judicial review of decision).
STANDARD OF REVIEW
The proper standard of review to utilize in this case is complicated by the fact that many of the issues are multifaceted, requiring the application of various standards in achieving a final resolution. In light of this fact and for efficiency, we will attempt to summarize the various standards that will be employed in this appeal.
Several of the issues raised in this appeal involve statutory construction, which is a question of law that is reviewed de novo.
See Bragg v. Edwards Aquifer Auth.,
71 S.W.3d 729, 734 (Tex.2002);
USA Waste Servs. of Houston, Inc. v. Strayhorn,
150 S.W.3d 491, 494 (Tex.App.-Austin 2004, pet. denied). In construing a statute, we must ascertain the legislature’s intent in enacting the statute.
Fleming Foods of Tex. v. Rylander,
6 S.W.3d 278, 284 (Tex.1999). In making this determination, courts should look to the plain mean ing of the words used in the statute.
See Fireman’s Fund County Mut. Ins. Co. v. Hidi,
13 S.W.3d 767, 768-69 (Tex.2000). We presume that every word was deliberately chosen and that excluded words were left out on purpose.
USA Waste Servs.,
150 S.W.3d at 494 . When determining legislative intent, the entire act, not isolated portions, must be considered.
Jones v. Fowler,
969 S.W.2d 429, 432 (Tex.1998). We may also consider the “object sought to be attained” by enacting the statute, the “circumstances under which the statute was enacted,” the “consequences of a particular construction,” and the interpretations of the statute made by an agency. Tex. Gov’t Code Ann. § 311.023 (West 2005);
see City of Austin v. Southwestern Bell Tel. Co.,
92 S.W.3d 434, 442 (Tex.2002). Moreover, so long as the interpretation is reasonable and consistent with the statute, we give serious consideration
*16
to an agency’s interpretation of a statute.
Continental Cas. Co. v. Downs,
81 S.W.3d 803, 807 (Tex.2002);
see Southwestern Bell Tel. Co., 92
S.W.3d at 441-42. This is particularly true when the statute concerns a complex subject matter.
Railroad Comm’n v. Coppock,
215 S.W.3d 559, 563 (Tex.App.-Austin 2007, pet. denied);
see also USA Waste Servs. of Houston, Inc. v. Strayhorn,
150 S.W.3d 491, 494 (Tex.App.-Austin 2004, pet. denied) (recognizing that legislature intends to provide agencies with centralized expertise in regulatory areas with large degree of latitude in accomplishing regulatory functions). However, courts do not defer to administrative interpretations regarding questions that are not within the agency’s expertise or that deal with nontechnical questions of law.
USA Waste Servs.,
150 S.W.3d at 494-95 .
Several issues also involve determinations regarding the Commission’s authority. As an agency, the Commission is a creation of the legislature and, therefore, “has no inherent authority.”
Public Util. Comm’n v. City Pub. Serv. Bd.,
53 S.W.3d 310 , 316 (Tex.2001). For this reason, the Commission possesses only those powers “expressly conferred upon it.”
Id.
However, when conferring a power upon an agency, the legislature also “impliedly intends that the agency have whatever powers are reasonably necessary to fulfill its express functions or duties.”
Id.
But an 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.
Finally, several of the issues question whether many of the Commission’s actions were adequately supported by the evidence presented. We review these types of questions under a substantial-evidence standard. Tex. Util.Code Ann. § 15.001 (West 2007) (stating that judicial review of agency action is under substantial-evidence standard); Tex. Gov’t Code Ann. § 2001.174 (West 2000) (allowing court to reverse agency determination if it is not supported by substantial evidence). Under this standard, we are prohibited from substituting our judgment for the Commission’s “as to the weight of the evidence on questions committed to agency discretion.”
Cities of Abilene, San Angelo, & Vernon v. Public Util. Comm’n,
146 S.W.3d 742, 748 (Tex.App.-Austin 2004, no pet.) (citing Tex. Gov’t Code Ann. § 2001.174). In making this determination, we are not asked to verify whether “the agency reached the correct conclusion, but whether some reasonable basis exists in the record for the agency’s action.”
Id.
In fact, the evidence may actually preponderate against the Commission’s finding and be upheld as long as there is enough evidence to suggest that the Commission’s “determination was within the bounds of reasonableness.”
Id.
DISCUSSION
The Commission’s Primary Market Valuation
Market Valuation
Before addressing the various parties’ arguments regarding the Commission’s primary market valuation, we will review the various methods by which a utility may calculate its stranded costs. The utilities code lists four primary market-based valuation methods and one alternative method for utilities to calculate the market value of generation assets — a necessary step for calculating stranded costs.
10
The language
*17
of the statute places the burden of properly calculating the market value of the assets on the utility. Section 39.262 of the utilities code mandates that “for the purpose of finalizing the stranded costs estimate,” “the affiliated power generation company
shall
” calculate the market value of the generation assets by using one of four methods: (1) the sale-of-assets method; (2) the stock-valuation method; (3) the partial-stock-valuation method; or (4) the exchange-of-assets method. Tex. Util.Code Ann. § 39.262(h) (emphasis added); 16 Tex. Admin. Code § 25.263 (f)(1) (2007);
see also
Tex. Gov’t Code Ann. § 311.016 (West 2005) (explaining that when construing statutes, courts should interpret “shall” as imposing duty).
The alternative method is found in subsection 39.262(i).
See
Tex. Util.Code Ann. § 39.262(f); 16 Tex. Admin. Code § 25.263 (f)(2) (2007). Under this method, the market value of the generation assets is ascertained by performing an additional ECOM calculation using “updated company-specific inputs.” Tex. Util.Code Ann. § 39.262(i).
Under the sale-of-assets method, the market value is determined by the “total net value realized from the sale” of the assets if they have been sold in a “bona fide third-party transaction under a competitive offering.”
Id.
§ 39.262(h)(1). The exchange-of-assets method applies when generation assets have been transferred “in a bona fide third-party exchange transaction.”
Id.
§ 39.262(h)(4). Under this method, the market value of the assets that were transferred may be determined by an independent appraisal of the assets.
Id.
If some or all of the generation assets have been transferred to “one or more affiliated or nonaffiliated corporations,” the market value of those transferred assets can be determined by using either the stock-valuation method or the partial-stock-valuation method. Both methods use the average closing price of the stocks of the corporation or corporations possessing the assets to determine the market value of those assets.
Id.
§ 39.262(h)(2), (3).
The Joint Applicants chose to employ the partial-stock-valuation method. A party may use this method when a utility or its affiliated power-generation company has transferred generation assets to a corporation and “at least 19 percent, but less than 51 percent, of the common stock” of the corporation “is spun off and sold to public investors through a national stock exchange.”
Id.
§ 39.262(h)(3). Under this method, the market value is determined by the average daily closing price of the stock “over 30 consecutive trading days.”
Id.
The 30-day period is chosen by the Commission, but it must occur within 120 days of the date on which the affiliated utilities file their joint application to recover stranded costs.
Id.; see id.
§ 39.262(c) (mandating joint filing).
Because the amount of stock spun off under this method can range from 19% to 51%, it is possible that less than half of the corporation’s stock will be publicly traded and, therefore, that the corporation’s majority stockholders will have complete control over the actions of the corporation. The effect of this control might increase the value of the stock privately held, rendering the average closing price of the publicly-traded stock an inaccurate measure of the true value of the stock. For this reason, the utilities code authorizes the Commission to appoint a panel of experts to determine whether this effect, called a control premium, is present.
Id.
§ 39.262(h)(3);
Reliant
I, 101 S.W.3d at 144 (explaining that “control premium is the additional value that a block of shares obtains by virtue of the fact that it carries
*18
with it the power to control the corporation”)- ⅛ other words, the panel determines the difference between the actual value of the stock and the amount that it is publicly traded for. If the panel determines that a control premium exists, the Commission shall adopt the panel’s determination of the actual value of the stock but cannot “increase the market value by a control premium greater than 10 percent.” Tex. Util.Code Ann. § 39.262(h)(3). The determination of the Commission “based on the finding of the panel conclusively establishes the value of the common stock.”
Id.
Over a year before the final true-up proceeding, CenterPoint distributed a little over 19% of Genco’s stock to CenterPoint’s shareholders. After distributing the stock, CenterPoint determined the market value of Genco’s generation assets by using the partial-stock-valuation method. By utilizing this method, CenterPoint determined that the market value for Genco’s generation assets was $2,907 billion.
Because the majority of Genco’s stocks were owned by CenterPoint and not traded publicly, the Commission appointed a panel to determine if a control premium existed.
See id.
The panel determined that a control premium existed and that CenterPoint’s valuation did not accurately reflect the actual value of Genco’s stock. The panel determined that the actual value of the stock was approximately 17% higher than its trade value.
See id.
§ 39.262(h)(3) (requiring Commission to adopt determination of panel but prohibiting it from increasing value of stock by more than 10%).
Ultimately, however, the Commission concluded that the partial-stock-valuation method could not be employed because less than 19% of Genco’s stock had actually sold on a national stock exchange despite the fact that 19% had been distributed to CenterPoint’s stockholders. In an attempt to find an alternative method for determining market value, the Commission reviewed other estimates for Genco’s market value, including the report by the control-premium panel. After performing its own analysis, the Commission concluded that the market value of the assets was higher than the amount originally calculated by the Joint Applicants. Because of this, the Commission reduced the Joint Applicants’ stranded-cost recovery to an amount that was less than the amount that they originally requested. The district court affirmed the Commission’s use of an alternative method for estimating the value of the generation assets and its reduction to the Joint Applicants’ recovery.
The Joint Applicants Failed to Satisfy the Requirements of the Parbial-Stockr-Valuation Method
In their first issue on appeal, the Joint Applicants contend that the Commission erred when it concluded that the partial-stock-valuation method could not be employed. Under this method, the market value of generation assets is determined by using the average trading price of the stock of the corporation or corporations possessing the assets if “at least 19 percent, but less than 51 percent, of the common stock of each corporation is
spun off and sold
to public investors through a national stock exchange.” Tex. Util.Code Ann. § 39.262(h)(3) (emphasis added);
see also Black’s Law Dictionary
974 (6th abridged ed.1991) (defining “spin-off’ as something that occurs when part of corporation’s assets and stocks are transferred to new corporation).
In August 2002, CenterPoint transferred all of its generation assets to Genco. Six months later, CenterPoint distributed or spun off approximately 19% of Genco’s shares to CenterPoint shareholders. After the initial distribution, the stocks were list
*19
ed on the New York Stock Exchange and were sold to public investors starting in January 2003. The stocks continued to be sold to public investors through the time of the true-up application in March 2004.
See
16 Tex. Admin. Code § 25.263 (2007) (time for filing true-up application).
Although CenterPoint did spin off 19% of Genco’s stock, not all of that stock was subsequently traded on a national stock exchange. For example, some of the distributed stock was placed into the retirement accounts of various CenterPoint employees and was not sold on a stock exchange. During the true-up proceeding, several employees testified that they received stocks from the spin-off and did not sell the stocks by the time of the proceeding. As a result, less than 19% of the stock actually changed ownership in the stock market. For this reason, the Commission concluded that the partial-stock-valuation method could not be used.
The Joint Applicants aver that subsection 39.262(h)(3) does not require that all 19% of the spun-off stock be sold on a national stock exchange.
See
Tex. Util. Code Ann. § 39.262 (h)(3). Rather, they assert that the requirements that stock (1) be spun off and (2) sold on a national stock exchange refer to two separate events. Stated differently, while the Joint Applicants acknowledge that at least 19% of the stock had to be spun off, they do not believe that all of the spun-off stock must subsequently be sold in a stock market. Rather, they assert that the “sold” requirement is satisfied as long as some of the stock was traded in a stock exchange. Similarly, they contend that the word “sold,” when read in the context of the statute, merely means that the stock must be offered for sale, not that it also be purchased, and refer to various definitions of the word “sell” to support this assertion.
See, e.g., Webster’s New Collegiate Dictionary
1051 (1st ed.1973).
The Joint Applicants also insist that interpreting the partial-stock-valuation method as requiring that all 19% of the distributed stock be sold in a stock exchange is tantamount to demanding an “unworkable and impossible requirement that defeats the entire purpose of the valuation statute.” Essentially, they argue that although market value is determined through average closing prices, many stock holders choose to retain ownership of their stock rather than sell it and that this retention plays a key role in establishing the true market value of stock. In other words, they argue that the rapid sale of stocks can lead to deflated stock prices but that stock retention helps to create a higher stock price by providing a stabilizing effect and by demonstrating that the stock is a desirable investment. Further, they assert that the benefit obtained through retention would cease to exist if all of the spun-off stock has to be sold prior to the true-up. Moreover, they insist that although not all 19% was sold, enough of the shares were sold and resold to establish an accurate market value. Specifically, they note that although 15.2 million shares were originally distributed, Genco stocks were traded 37.8 million times between January 2003 and March 2004. Finally, they assert that a rigid requirement that a utility not only spin off 19% of its stock but that 19% also be publicly traded would effectively require a utility to spin off more than 19% of stock in order to guarantee that at least 19% is traded, which they urge would lead to significant tax penalties. Specifically, they argue that CenterPoint and Genco would not have been able to file a joint tax return if more of Genco’s stock had been distributed.
See
26 U.S.C.A. § 1504 (West 2002) (defining “affiliated corporation” as one in which parent corporation owns 80% of corporation’s stock).
*20
When it interpreted the relevant statutory language, the Commission determined that the phrase “sold ... through a national stock exchange,” as used in the statute, means that the stock must actually be traded through a national stock exchange (i.e. offered for sale and purchased) and not just offered for sale.
11
From this, the Commission reasoned that at least 19% of the stock must be spun off and subsequently traded in a national stock exchange in order to satisfy the requirements of the statute.
We believe that the Commission’s interpretation is correct for several reasons. First, the use of the word “and” without the insertion of a new subject in the phrase “spun off and sold” indicates that both phrases apply to the language immediately preceding them: “at least 19 percent, but less than 51 percent, of the common stock is.”
See
Tex. Util.Code Ann. § 39.262(h)(3). Explained another way, the statute requires that (1) at least 19% of the stock be spun off and (2) at least 19% of the stock be sold.
Second, there are other definitions of the word “sold” that do not mean simply to offer for sale. For example, “sell” can also mean “to give up (property) to another for money or other valuable consideration.”
Webster’s New Collegiate Dictionary
1051 (1st ed.1973).
12
Keeping in mind that the word “sold” is the past tense of “sell,” plugging this definition into the statute leads to the conclusion that to satisfy the partial-stock-valuation requirements, at least 19% of the stock must have been
*21
purchased by public investors prior to the true-up proceeding.
We believe that this construction of the statute more accurately reflects the legislative intent than the Joint Applicants’ interpretation. This construction comports with the use of the word “sold” in other provisions of the utilities code. For example, under the sale-of-assets method for determining market value, a utility may establish the market value of generation assets if the assets have been “sold.” Tex. Util.Code Ann. § 39.262(h)(1). When the word “sold” is read in the context of the remainder of the sentence, it becomes clear that “sold,” as used in this subsection, does not mean to offer for sale. The relevant portion of the provision provides as follows: “the total net value
realized
from the sale establishes the market value of the generation assets
sold.” Id.
(emphases added).
This interpretation is also consistent with the emphasis placed on establishing an accurate market value apparent in the entire market-valuation subsection.
Jones v. Fowler,
969 S.W.2d 429, 432 (Tex.1998) (providing that when construing statutes, courts should look to entire act). Each market valuation method listed in subsection 39.262(h) requires that certain minimum conditions be met before the utility may employ the method. Tex. Util.Code Ann. § 39.262(h). For example, a utility may employ the sale-of-assets method only if its generation assets are sold “in a bona fide third-party transaction under a competitive offering.”
Id.
§ 39.262(h)(1). Similarly, the exchange-of-assets method may be employed only if the generation assets are transferred “in a bona fide third-party exchange transaction.”
Id.
§ 39.262(h)(4). Moreover, under this method, the market value of the assets may be determined by offering the assets for sale if the offer is made in a way guaranteeing “broad public notice of the offer and a reasonable opportunity for other parties to bid on the asset.”
Id.
These requirements are designed to ensure that an accurate market value for the generation assets is calculated in order to comply with the overriding mandate present throughout the statutory scheme: that a utility be allowed to recover but not ov-errecover its stranded costs.
See, e.g., id.
§§ 39.252, .262(a).
13
Given the strong legislative directive that market calculations be based on real market forces, it seems logical to conclude that the legislature fully intended that a large portion of the company’s stock — at least 19% — actually trade on a public stock exchange to ensure that an accurate market value is obtained.
See id.
§ 39.251(4) (defining “market value” as value of assets if they had been bought and sold in “bona fide third-party transaction” or “on the open market”).
Moreover, the Joint Applicants’ interpretation would lead to unreasonable results.
See Lowe v. Rivera,
60 S.W.3d 366, 369 (Tex.App.-Dallas 2001, no pet.) (stating that statutes should not be construed in manner that leads to absurd results). Under their interpretation, the statute would be satisfied if 19% of the stock was spun off and offered for sale on a public stock exchange but only a few stocks actually sold through the exchange. Essentially, under the Joint Applicants’ interpretation, the market value from the sale of a handful of stocks — or even one share — could be used as a valid basis for determining
*22
stranded costs. This does not comport with the utilities code’s insistence on utilizing, to the extent possible, actual competitive market forces and reasonable business practices to determine market value.
We also disagree with the Joint Applicants’ assertion that it would be impossible to comply with the requirements of the partial stock valuation. Although it may be difficult to have at least 19% of the spun-off stock actually sell on a stock exchange if only 19% is spun off, utilities can attempt to assure compliance with the statute by spinning off more than the minimum amount required. In fact, under the partial-stock-valuation method, a utility may spin off between 19 and 51% of the stock. Tex. Util.Code Ann. § 39.262(h)(3). By spinning off more than 19%, the Joint Applicants could have obtained whatever benefit might arise from certain stock holders retaining their stock and still complied with the statute by selling 19% of the stock on a national stock exchange.
Furthermore, spinning off more than 19% is not the only way the statute could have been satisfied. The Commission argues that the Joint Applicants could also have chosen to
comply
with the statute by distributing the stock through an initial public offering.
14
See Walden v. Affiliated Computer Servs.,
97 S.W.3d 303, 327 (Tex.App.-Houston [14th Dist.] 2003, pet. denied) (explaining that initial public offering “is the commonly used term for the first offering of equity securities of an issuer to the public pursuant to a registration statement”). Under this method, public investors would purchase Genco stock from an underwriter shortly after the initial offering is made. Because the sale would involve a transfer to public investors without first going through CenterPoint shareholders, the Commission contends that the partial-stock-valuation requirements would be met as long as more than 19% of the stock was purchased in the initial offer.
15
In other words, no more than the desired amount of stock would need to be distributed because the stock is sold directly to public investors.
Although the Joint Applicants acknowledge that an initial public offering would have satisfied the necessary requirements, they insist that the market conditions during 2003 would not have allowed a successful public offering. Essentially, they argue that an offering of 15.2 million newly issued stocks would have deflated the value of the stock.
16
Even if the value of the stock would have been temporarily lowered, the Joint Applicants appear to concede that the value would have stabilized over time at a value similar to that found by spinning off the stock first and then offering it for sale on a stock exchange. This undercuts their assertion that it would have been impossi
*23
ble to satisfy the partial stock valuation. It also seems to indicate that they could have satisfied the partial stock valuation without having to distribute significantly more than 19% of Genco’s stock, thereby obviating their tax concerns. In addition, the fact that the utilities code allows the partial stock valuation to be used for spinoffs of amounts much larger than 19% of a utility’s stock indicates that the partial-stock valuation provision was not enacted solely to allow affiliated utilities to file joint tax returns. Moreover, we must assume that when the legislature chose the range of values that would satisfy the spinoff requirement of the partial stock valuation, it was aware that utilities might incur negative tax consequences if they were required to distribute more than 19% of the stock.
See
Tex. Util.Code Ann. § 39.262(h)(3). As a result, we cannot conclude that the legislature crafted the spinoff requirements so as to prevent potential negative tax consequences for the utilities who complied.
From the numerous methods for calculating market value described in the utilities code, we can infer that it was the legislature’s intent to afford the utilities discretion to consider their unique circumstances and the relevant market conditions when deciding which method to use. It was within the utilities’ discretion to consider and trade off the relative benefits and costs (e.g. taxes) when selecting a valuation method. This scheme does not, however, enable utilities to partially comply with the mandatory requirements in order to avoid a potential business cost.
We must also assume that when the legislature enacted this statute, it was aware of the possibility that the recipients of a stock spin-off may hold onto their stocks for an extended period of time and that stock that is sold on a stock exchange might be resold prior to the true-up proceeding. In light of this, the legislature still required a utility to spin off and sell at least 19% of the relevant stock to comply with the partial-stock valuation method. For this reason, we also disagree with the Joint Applicants’ assertion that the subsequent reselling of the Genco stock in the stock market satisfied the legislative goal of establishing an accurate market value.
17
For all the reasons previously given, the Commission’s interpretation requiring that a minimum proportion of a utility’s total stock be sold in the stock market in order to accurately determine market value is correct and consistent with the relevant statutory language. The Joint Applicants failed to comply with this minimum requirement. Accordingly, the Commission correctly determined that the partial-stock method could not be used to calculate the market value of the generation assets.
The Commission Had the Authority to Consider Other Valuation Methods
The Utility Counsel and the Customers agree that the requirements of the partial-stock method were not complied with but criticize the Commission’s decision to estimate the market value of the generation assets by a method not specifically listed in the utilities code. First, the Customers assert that the Commission should not have allowed the Joint Applicants to recover any stranded costs because they failed to meet their burden of establishing a viable market value. Essentially, the Customers assert that the burden of proving stranded costs is on the utilities and insist that if a utility fails to satisfy this burden,
*24
it should not be awarded stranded costs.
18
See
Tex. Util.Code Ann. §§ 39.252 (stating that utility is allowed to recover its “verifiable” stranded costs), .262(h) (requiring utility to “calculate its stranded costs”);
see also id.
§ 39.003 (establishing that in contested cases, burden of proof “is on the incumbent electric utility”).
However, this assertion ignores the clear legislative mandate that utilities be allowed to recover their stranded costs.
See, e.g., id.
§§ 39.001(b)(2) (“in public interest to ... allow utilities ... to recover” stranded costs), .252 (“utility is allowed to recover all of its net, verifiable, nonmitiga-ble stranded costs”). In fact, an entire subchapter of the utilities code is dedicated to describing the process of stranded-cost recovery.
See id.
§§ 39.251-265 (entitled “Recovery of Stranded Costs Through Competition Transition Charge”). Although the Utility Counsel and the Customers correctly point out that the utilities code places the burden of determining market value on the utilities,
id.
§ 39.262(h), nothing in the code indicates that the failure of a utility to satisfy one of the market-valuation requirements should result in an automatic denial of the right to recover any stranded costs. Construing the utilities code in this manner would run afoul of the statutory scheme governing the transition to a competitive energy market and ensuring that a former regulated utility not be disadvantaged through the transition.
In the alternative, the Customers argue and the Utility Counsel agrees that after concluding that the partial-stock method could not be utilized, the Commission should have used one of the other permissible valuation methods to calculate market value.
See id.
§ 39.262(h), (i).
We disagree. After considering the possibility of utilizing one of the other listed methods, the Commission concluded that none of the other methods listed in the utilities code could have been employed in this case because their requirements were not met. The stock-valuation method requires that more than 51% of the common stock of a transferee corporation be “spun off and sold to public investors.”
Id.
§ 39.262(h)(2). However, as discussed earlier, less than 19% of Genco’s stock was actually spun off and sold. The exchange-of-assets method could also not be employed because Genco did not transfer any of its generation assets “in a bona fide third-party exchange transaction.”
See id.
§ 39.262(h)(4).
Similarly, the Commission also concluded that the two methods proposed by the Customers and the Utility Counsel — the sale-of-assets method and the alternative method found in subsection 39.262(i)— could not be employed. Subsection (i) reads, in relevant part, as follows:
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 [the stock-valuation method and partial-stock-valuation method], the electric utility shall quantify its stranded costs for nuclear assets using the ECOM method .... using updated company-specific inputs....
Id.
§ 39.262(i) (emphases added). The transfer of assets is a necessary component of the market valuations obtained by using either the stock-valuation method or the partial-stock-valuation method. Although the Joint Applicants did not satisfy the other requirements necessary for these
*25
two methods, namely the sale of a sufficient number of stocks in a public stock exchange, they did transfer all their generation assets to Genco. In light of this, the Commission concluded that the ECOM model could not be used to estimate market value. This determination is reasonable and consistent with the relevant statutory language, and we agree that is what the legislature intended.
The sale-of-assets provision reads, in relevant part, as follows:
If, at any time after December 31, 1999, an electric utility ... has
sold
some or all of its generation assets ... in a bona fide third-party transaction under a competitive offering, the total net value realized from the sale establishes the market value of the generation assets sold.
Id.
§ 39.262(h)(1) (emphasis added). The Customers argue that in July 2004 Center-Point entered into a binding agreement to sell its generation assets to a third party during the true-up proceeding and that the Commission should have used the amount offered to ascertain the value of the generation assets because the offered price was in the record before the Commission. Further, in light of the statutory language stating that the sale of assets “at any time after December 31, 1999,” may be used to establish market value,
see id.,
they ask this Court to take judicial notice of the fact that Genco was actually sold for the amount offered after the Commission issued its final order or, alternatively, to remand the case in order for the Commission to take notice of the completed sale. In related contentions, the Utility Counsel argues that the failure of the Commission to use the sale price of Genco to establish market value allowed the Joint Applicants to overrecover for stranded costs in violation of the legislative prohibition.
See id.
§ 39.262(a). Essentially, it argues that the Commission’s market value estimate was much lower than the sale price, which allowed the Joint Applicants to recover more for stranded costs than they would have been allowed to if the sale-of-assets method had been employed.
The sale-of-assets method requires that the generation assets be “sold” prior to the stranded-cost reconciliation.
Id.
§ 39.262(h)(1). Although subsection (h)(1) does refer to a sale occurring “any time after December 31, 1999,” the Commission concluded that the word “sold,” meaning a completed act, necessarily limits consideration of a sale for market-valuation purposes to sales occurring before the true-up reconciliation.
See id.
Although the offer was made before the Commission issued its final order, the sale was not finalized until after the true-up proceeding, and therefore, the Commission concluded that any attempt to use the subsequent sale of Genco as the sole basis for determining market value would be improper and would be contrary to the provisions of the utilities code.
19
The Commission’s construction of the sale-of-assets provision is reasonable and consistent with the relevant statutory language, and we are persuaded the interpretation accurately reflects the intention of the legislature. Accordingly, it would be improper for this Court to take judicial notice of a sale oc
*26
curring after the administrative record has closed.
20
For all the reasons previously given, we conclude that the Commission did not err when it failed to use one of the other valuation methods listed in the utilities code.
The Utility Counsel and the Customers also argue that by employing a valuation method not specifically authorized by statute, the Commission exceeded its authority.
See id.
§ 39.262; 16 Tex. Admin. Code § 25.263 ;
see also
Tex. Util.Code Ann. § 12.001 (West 2007) (explaining that Commission “exercises the jurisdiction and powers conferred by this title”); Tex. Gov’t Code Ann. § 2001.174(2) (West 2000) (requiring court to reverse case if agency conclusions are “in excess of the agency’s statutory authority”).
21
In support of their arguments, the Customers invoke the doctrine of
expressio unius est exclu-sio alterius. See Mid-Century Ins. Co. v. Kidd,
997 S.W.2d 265, 273 (Tex.1999) (explaining that doctrine stands for proposition that expression of one thing means exclusion of all others). They argue that the legislature specified five methods for determining market value and, therefore, necessarily excluded all other methods of performing that task.
We do not believe that the doctrine of
expressio unius est exclusio alterius
prohibits the Commission from engaging in the complained-of action.
First, we note that the doctrine is only an aid for determining legislative intent and should not be employed in a way that leads to an unreasonable result.
Id.
at 274 .
Second, the Utility Counsel and the Customers’ interpretation fails to account for the fact that fulfilling the various requirements for a valuation method can take a great deal of time but that the deregulation process has relatively quick deadlines.
See, e.g.,
Tex. Util.Code Ann. § 39.262(h)(2), (3) (both requiring that stock be traded on exchange for more than one year before valuation method may be employed). Under the Utility Counsel and the Customers’ interpretation, if a utility is ultimately unable to fulfill the requirements of a valuation method and there is no time to fulfill the requirements of another method, the utility would not be entitled to recover for stranded costs. Given the tremendous legislative emphasis placed on the need for stranded-cost recov
*27
ery, we conclude that this interpretation is inconsistent with that mandate.
We also do not believe that the Commission exceeded its authority when it developed an alternative valuation method. As discussed previously, the Joint Applicants did not select another market-valuation method, and the Commission properly concluded that none of the other listed methods could have been employed because their requirements were not satisfied. As a result, the Commission faced the problem of reconciling an overwhelming statutory mandate that utilities be allowed to recover their stranded costs with the fact that the specific methods listed for determining stranded costs could not be employed.
22
To resolve this conflict, the Commission chose to utilize the definition of “market value” found in the utilities code as a basis for developing a substitute valuation method.
See id.
§ 39.251(4) (defining “market value” as “the value the assets would have if bought and sold in a bona fide transaction on the open market”). As discussed more thoroughly in the next section, in determining the assets’ market value, the Commission relied extensively on information already in the record: namely the control-premium panel’s report and the offer to buy Genco. Both pieces of information were indicia of the market value of Genco’s assets. Moreover, although specified for another use, the panel’s report was a legislatively authorized tool to be used during true-up proceedings.
Id.
§ 89.262(h)(3).
In light of the Commission’s predicament, its important role in deregulation, and the information chosen to estimate market value, we cannot conclude that the Commission acted in an arbitrary manner or exceeded its authority by using an alternative valuation method in order to ensure that a critical legislative mandate was met.
The Customers also assert that by developing a new valuation method, the Commission has improperly created a new power for administrative expedience and that the new power contradicts the provisions of the utilities code. In support of their arguments, the Customers refer to subsection 39.252(d), which imposes a duty on utilities to engage in commercially reasonable activities to reduce their stranded costs.
Id.
§ 39.252(d). It also authorizes the Commission to “consider” the utilities’ conduct when determining the amount of stranded costs but also cautions that “nothing in this section authorizes the [Cjommission to substitute its judgment for a market valuation of generation assets determined under” the sections listing the five methods for determining market value.
Id.
The Utility Counsel and the Customers argue that by developing an alternative method for valuation, the Commission has substituted its judgment for a market valuation and, therefore, violated the statute.
We do not believe that the Commission impermissibly created a new power in contravention of the utilities code. Contrary to the assertions of the Utility Counsel and the Customers, the Commission’s actions did not violate subsection 39.252(d). That provision states that the Commission may not “substitute its judgment for a market valuation ... determined under Sections 39.262(h) and (i).”
Id.
As previously discussed, the methods for determining market valuation under subsections (h) and (i) could not have been employed to ascertain market value. Therefore, the Commission
*28
was not substituting its opinion for a market valuation calculated by using one of those methods.
Second, the cases that the Customers rely on in support of their argument that by using an alternative valuation method, the Commission has impermissibly created a new power are distinguishable.
See Public Util. Comm’n v. GTE-Southwest, Inc.,
901 S.W.2d 401 (Tex.1995);
Denton County Elec. Co-op. v. Public Util. Comm’n,
818 S.W.2d 490 (Tex.App.-Texarkana 1991, writ denied). In both cases, the utilities code specified that the Commission had the authority to engage in an action only when certain conditions were met.
GTE-Southwest, Inc.,
901 S.W.2d at 407 ;
Denton,
818 S.W.2d at 492 . However, the parties argued about whether the Commission also possessed the implied power to engage in the same activity when the conditions were not present.
GTE-Southwest, Inc.,
901 S.W.2d at 404 ;
Denton,
818 S.W.2d at 492 .
In this case, the Commission is not asking this Court to conclude that, despite statutory language authorizing the Commission to act only under certain circumstances, it has an implied authority to act when the circumstances are not present. On the contrary, the Commission is asking this Court to conclude that it has the authority to act to fulfill a legislative mandate when the enumerated methods for compliance are not applicable to the present circumstances. Specifically, the Commission asks this Court to conclude that when all the permissible methods of calculating market value are unavailable because their conditions are not met, the Commission has the implied authority to devise an alternative method for calculating market value in order to comply with the legislative directive that utilities recover for stranded costs that they have incurred. Given the strong legislative mandate, we must conclude that the Commission’s authority to use an alternative valuation method is “reasonably necessary to fulfill a function or perform a duty that the Legislature has expressly placed in the” Commission’s purview.
See GTE-Southwest, Inc.,
901 S.W.2d at 407 ; see
also State v. Public Util. Comm’n,
883 S.W.2d 190, 194-97, 204 (Tex.1994) (concluding that Commission had implied authority to alleviate impact of regulatory lag by deferring accounting, despite fact that this power was not explicitly listed in utilities code). Accordingly, we must also conclude that the Commission’s actions did not amount to an impermissible creation of a new power.
The Method Chosen by the Commission was Proper
As part of its valuation, the Commission considered the control-premium panel’s report. In its report, the panel listed a range of possible values estimating the actual value of the Genco’s stock. The value ultimately chosen by the Commission was the mid-value of the proposed range.
23
Through several arguments, the Utility Counsel and the Customers assert that even if the Commission was allowed to use an alternative valuation method, the Commission’s utilization of the report as a method for asset valuation was procedurally improper.
First, they contend that it was error to rely on the panel’s report because it was prepared solely for the purpose of determining whether a control premium existed and not for determining the statutorily required estimate of Genco’s market val
*29
ue.
24
Further, they argue that by using the panel’s report as a basis of estimating market value, the Commission impermissi-bly made the panel the final fact-finder for market valuation. Although they acknowledge that, under the utilities code, the Commission is required to adopt the panel’s determination regarding whether a control premium exists,
see
Tex. Util.Code Ann. § 39.262(h)(3) (requiring Commission to “adopt” control-premium amount determined by panel), they argue that there is no statutory authority for allowing the panel to serve as a final fact-finder for the market valuation of generation assets.
Second, they argue that the Commission’s utilization of the panel’s report violated their due process rights because they were not given prior notice and an opportunity to be heard regarding the use of the control panel’s report as a tool for market valuation.
See
Tex. Gov’t Code Ann. § 2001.051 (explaining that party is entitled to notice prior to hearing and opportunity to present and respond to evidence);
Madden v. Texas Bd. of Chiropractic Exam’rs,
663 S.W.2d 622, 626-27 (Tex.App.-Austin 1983, writ ref'd n.r.e.) (“To be meaningful, ‘notice’ and ‘hearing’ require previous notice and a hearing relative to the issues of fact and law which will control the result to be reached”). Further, they argue that they were unable to bring forth evidence refuting the panel’s findings related to the market value of Genco’s stock. Moreover, they contend that because the panel’s report was used for ascertaining the market value of Genco’s generation assets, they should have been allowed to cross-examine the panel members.
See Smith v. Houston Chem. Servs., Inc.,
872 S.W.2d 252, 278 (Tex.App.-Austin 1994, writ denied) (explaining that procedural rights “encompassed by due process of law are generally recognized to be as follows: notice of hearing; the opportunity to present argument and evidence and to rebut and test opposing evidence and argument by cross-examination or other appropriate means; appearance with counsel; and a decision by a neutral decision maker based on evidence introduced into the record of the hearing”).
Finally, they allege that the Commission’s .utilization of the panel’s report was problematic because the panelists were not required to comply with contested-case requirements.
See, e.g.,
Tex. Gov’t Code Ann. §§ 2001.051-.178 (West 2000) (rules governing contested cases). In particular, they assert that the panelists were allowed to communicate privately with third parties, were allowed to obtain information from external sources when conducting them analysis, and were allowed to conduct their own research.
These challenges to the panel’s final report were likely waived when the report was admitted into the record with no objection from the Customers or the Utility Counsel. However, even assuming that the Customers and the Utility Counsel’s complaints were preserved for consideration on appeal, we conclude that the Commission’s consideration of the panel’s report was not procedurally improper.
The Commission’s reliance on the control-premium report as an aid for determining market value did not impermis-sibly elevate the status of the panel to final fact-finder for market-value determinations. Although the panel’s decision about the existence of a control premium would have been binding upon the Commission had the partial-stock-valuation method
*30
been used,
see
Tex. Util.Code Ann. § 39.262(h)(3), the Commission was not bound by the panel’s conclusions when determining market value. The Commission merely used the panel’s estimate when making its own market-value determination.
See Central Power & Light Co. v. Public Util. Comm’n,
36 S.W.3d 547, 561 (Tex.App.-Austin 2001, pet. denied) (stating that as sole judge of weight to give testimony and evidence, Commission may consider range of values presented in making its final determination).
Moreover, although the Customers correctly point out that the control panel was convened solely for the purpose of determining whether a control premium existed, inherent within that determination was an estimation of the true market value of Genco’s stock.
See
Tex. Util. Code Ann. § 39.262 (h)(3) (explaining that control panel is composed of three financial experts “from the top 10 nationally recognized investment banks with demonstrated experience in the United States electric industry” and is assembled to determine whether value of publicly traded stock is “fairly representative of the total common stock equity or whether a control premium exists for the retained interest”).
25
In fact, in testimony given before the Commission, the panel’s purpose was described as determining a “fair market value for [Genco] in roughly the same time period as the valuation time period in this case.”
Furthermore, although the panel’s report was not used in the precise manner originally anticipated, the Customers and the Utility Counsel were on notice that the panel’s report would be used for the purpose of determining the true value of Genco’s stock.
See id.
Moreover, the panel provided all the relevant parties with notice of its actions and with the opportunity to be heard. First, the parties were given notice that the panel had been convened and that it would be evaluating the value of Genco’s stock. Second, the parties were informed that the panel would have several open hearings and were allowed to comment at the hearings regarding the panel’s proposed methods for making its determinations. Finally, the parties were allowed to file any concerns and information that they had that were relevant to the panel’s proposed analysis, including information related to market value, and the panel pledged to consider the filings when making its decision.
Because the parties were aware that the panel’s report would provide an estimate of Genco’s stock and that the evaluation would necessarily affect the Joint Applicants’ stranded-cost recovery, they had every incentive to participate in the panel’s determination and to provide evidence supporting their positions.
26
Moreover, the
*31
Customers and Utility Counsel argued that the requirements of the partial-stock valuation method might not have been satisfied and were allowed to present evidence regarding other market valuations that might be employed.
In addition, in making a due-process claim, a party must show that a due-process violation occurred and that he or she was harmed by that violation.
See Hammock v. Public Util. Comm’n,
131 S.W.3d 713, 730 (Tex.App.-Austin 2004, pet. denied); see
also
Tex. Gov’t Code Ann. § 2001.174 (prohibiting court from reversing agency decision unless “the substantial rights of the appellant have been prejudiced”). In making their due-process claims, the Customers and the Utility Counsel fail to specify what additional evidence they would have introduced had they been informed that the Commission would be utilizing the panel’s report when ascertaining the value of Genco’s stock.
See City of Corpus Christi v. Public Util. Comm’n of Tex.,
51 S.W.3d 231, 263 (Tex.2001).
Although the Customers and the Utility Counsel complain that they were not allowed to cross-examine the panel members, they cite to no authority for the proposition that cross-examining the panel members was appropriate and present no evidence that they filed a request to cross-examine the panel. Furthermore, the Customers and the Utility Counsel were given the opportunity to elicit testimony from and cross-examine witnesses that had information relevant to the panel’s determination, and the Commission questioned the panel members regarding their valuation methods.
Additionally, given the panel’s unique role in the true-up proceeding, it is not clear that the requirements of a contested case have any applicability to the panel’s determination. Essentially, the panel’s function is to determine whether a control premium exists and then to supply the Commission with that information; its role is not to make decisions regarding the outcome of the true-up proceeding.
See
Tex. Util-Code Ann. § 39.262(h)(3);
see also
Tex. Gov’t Code Ann. § 2001.060 (West 2000) (explaining that record consists of “data submitted to or considered by hearing officer or members of agency”). Furthermore, even if the contested-case restrictions should apply to the panel’s determination, the prohibition against ex parte communications in contested cases allows for ex parte communications when, as here, each party is given notice and allowed to participate. Tex. Gov’t Code Ann. § 2001.061(a) (West 2000). Regardless, the Commission did institute modified contested-case requirements to help ensure the panel’s independence: the panel (1) had to present all of the sources of information it relied on in making its determination, (2) had to keep a log of all its meetings and communications, and (3) was prohibited from communicating ex parte “with the Commissioners, the Policy Development Division staff assisting with the case ..., [and] any of the parties.”
In light of the preceding, we must conclude that the Commission’s use of the panel’s report was not procedurally improper. The Commission was faced with the dilemma of determining the market value of Genco’s stock when none of the methods listed in the utilities code could be employed. In resolving this dilemma, the Commission logically used a statutorily au
*32
thorized report estimating the actual value of Genco’s stock. It was not error for the Commission to do so.
See Texas Utils. Elec. Co. v. Public Util. Comm’n,
881 S.W.2d 387, 404 (Tex.App.-Austin 1994),
rev’d in part on other grounds,
935 S.W.2d 109 (Tex.1997) (concluding that, in rate-making context, if utility fails to persuade Commission that certain expenditures were prudent, Commission may consider other evidence in record to make disallowance determination).
In addition to contending that it was improper for the Commission to consider the report, the Customers and the Utility Counsel also attack the validity of the report and the methods employed by the panel for estimating the value of Genco’s stock. In particular, they argue that the panel’s report was flawed because it was based on theories rather than market transactions.
We disagree with the Customers’ critique of the factual validity of the panel’s report. In the previous section, we concluded that the Commission did not exceed its authority by deciding to use an alternative valuation method for determining market value. Now, in light of the Customers’ assertions, we review the Commission’s valuation to determine if it was supported by substantial evidence.
The Commission’s market valuation depended heavily on the control-premium panel’s report. In determining the actual value of Genco, the panel performed and considered several “financial and comparative analyses.”
First, it performed a discounted-cash-flow analysis. This analysis relied on financial projections, historical trends, and electricity and natural gas prices. Based on these factors, the panel estimated the discounted present-day value of Genco’s cash flow from 2004 to 2008. Second, it performed a precedent-asset-transaction analysis. This analysis relied on publicly available information regarding prior transactions involving generation assets. The panel used the sale price of these previous transactions to estimate the value of Genco’s generation assets. Third, it performed a public-market-comparables analysis. Essentially, the panel compared stock-market data for Genco to other “publicly-traded companies in the non-regulated power generation industry.” Finally, the panel considered the offer to purchase Genco announced in July 2004.
None of the valuation methods utilized by the panel were dependent on the sale of Genco stocks in a stock exchange. For that reason, the panel’s evaluation was not affected by the fact that less than 19% of Genco’s stocks actually traded on a stock exchange.
In light of the substantial factual underpinning of the panel’s report, we must conclude that a reasonable basis exists for the Commission’s valuation and, accordingly, that its valuation was supported by substantial evidence.
The Allegedly Unreasonable Business Practices were Irrelevant under the Primary Holding
The Customers and the Utility Counsel argue that, in its primary holding, the Commission should have made an additional reduction to the Joint Applicants’ recovery to account for conduct that was allegedly commercially unreasonable. The Commission made this reduction to the Joint Applicants’ recovery under its alternative holding but concluded that the reduction would have been inappropriate under the primary holding. In its alternative holding, the Commission estimated market value by using the partial-stock-valuation method even though all the requirements had not been met.
*33
The Commission’s reduction was based on an option that CenterPoint gave to Reliant Resources, Inc. (“Resources”) to purchase the shares of Genco stock that CenterPoint owned. The Commission determined that the option was not commercially reasonable because it imposed significant restrictions on how Genco could operate but did not require Resources to pay for the option. For this reason, the Commission concluded that by giving the option, CenterPoint failed to fully mitigate its stranded costs as required by statute.
See
Tex. Util.Code Ann. § 39.252(d) (requiring Commission to consider utility’s efforts to pursue commercially reasonable means to reduce its stranded costs when determining amount of recovery); 16 Tex. Admin. Code § 25.263 (e)(4) (specifying that if Commission determines that utility failed to mitigate, it may reduce net book value of generation assets).
The Commission determined that the commercial value of the option was $330,314,000. In other words, the $330,314,000 represents the amount of money that Genco should have received as compensation for the significant restrictions that it was encumbered with as a result of the option, or alternatively, it represents the reduction to the overall value of Genco due to the restrictions. After making this determination, the Commission reduced the amount of stranded costs that the Joint Applicants were entitled to recover by that amount and by an additional $177,874,089 to account for the taxes that would have been paid had the option been purchased. The total amount of the reduction was approximately $508 million. The district court affirmed the Commission’s determination to limit the application of the reduction to the alternative holding.
The Customers and the Utility Counsel agree that the reduction was appropriate but argue that the reduction should have applied to the Commission’s primary holding as well. Essentially, they argue that regardless of what valuation method was employed, the option was commercially unreasonable and that the Joint Applicants’ recovery should, therefore, be reduced irrespective of the valuation method chosen. They further contend that the Commission’s decision to limit the reduction to the alternative holding is arbitrary and capricious, unreasonable, and contrary to the directive in subsection 39.252(d) that the Commission consider a utility’s efforts to reduce its stranded costs when determining the amount of money that the utility is entitled to recover.
See
Tex. Gov’t Code Ann. § 2001.174 (listing grounds for reversing agency’s decision); Tex. Util. Code Ann. § 39.252 (d).
We disagree. Subsection 39.252(d) is not a tool that is used to punish utilities for commercially unreasonable conduct. Even if the provision allows the Commission to alter the amount that a utility is entitled to recover if the utility fails to “pursue commercially reasonable ways to reduce its potential stranded costs,” Tex. Util.Code Ann. § 39.252(d), there is no indication from the words used in that section or in any provision of the utilities code that this power is punitive in nature.
On the contrary, given the legislative directive compelling an accurate assessment of stranded costs, it seems logical to assume that any power that the Commission may have to alter the amount of recovery is limited to ensuring that the amount of stranded costs that a utility recovers corresponds to the actual costs that the utility incurred as a result of deregulation and was not intended to be used for punishing utilities for commercially unreasonable behavior. In other words, if the commercially unreasonable behavior benefits the utility financially and lessens
*34
the impact of the stranded costs, then the amount that the utility is entitled to recover should be modified. However, if the commercially unreasonable behavior has no financial impact or if the financial impact is either irrelevant to or accounted for in the valuation method chosen, then adjusting the amount of recovery would be contrary to the legislative directive.
In its primary holding, the Commission considered several factors when determining the market value of Genco’s stock. First, although the Commission correctly concluded the sale-of-assets method could not be used to estimate Genco’s market value, the Commission did consider the amount offered to purchase Genco when attempting to ascertain the market value of Genco’s assets. The offer came several months after the option expired and after the restrictions placed upon Genco by the option had ended. As a result, any detrimental effect on Genco’s value resulting from the option should have dissipated. Therefore, the offer’s usefulness as an estimate of Genco’s market value was arguably unaffected by the option.
However, even if the potentially negative effects of the option had not fully dissipated, the Commission did not rely solely on the proposed sale price when determining Genco’s market value. While performing its estimate, the Commission also considered the valuation report prepared by the control-premium panel. To establish Genco’s true value, the panel performed several analyses utilizing the following factors: the market value of other publicly traded companies, the price of electricity, historical trends, forecasted market conditions, and the amount obtained by the prior sale of generation assets. None of these analyses were affected by the option. Further, the actual value ultimately chosen by the Commission was the midpoint of the values calculated by the valuation panel.
After concluding that the various market valuations that it relied on in its primary holding were unaffected by the option, the Commission determined that it “did not need to examine the [Joint Applicants’] business practices” regarding the option and that no adjustment for commercially unreasonably behavior needed to be made. In light of the preceding, the Commission’s decision to limit the adjustment to its alternative holding was reasonable and did not violate subsection 39.252(d).
For all the reasons previously given, we conclude that the district court properly affirmed the Commission’s use of an alternative valuation method and its decision to limit the deduction for the option to its alternative holding.
Alternate Holding
Having concluded that the Commission possessed the authority to perform the market valuation it made under its primary holding, we need not address the parties’ arguments regarding the propriety of the Commission’s alternative holding, the propriety of the reduction to stranded-cost recovery due to the option given to Resources, or whether the reduction should have been “grossed-up” to account for federal taxes.
Excess Mitigation Credits
The Customers and the Utility Counsel also challenge the Commission’s decision to allow the Joint Applicants to recover, as stranded costs, $470 million for credits that CenterPoint had been ordered to give to Reliant and other retail electric providers. This decision was affirmed by the district court. In a separate issue, the Commission disagrees with the district court’s decision to allow the Joint Applicants to recover $180 million for interest on the credits that CenterPoint gave to
*35
Reliant. Before addressing the merits of these claims, we will review how these credits came to be awarded.
Although the provisions of the utilities code governing the recovery of stranded costs took effect in 1999, competition did not actually begin until 2002. Tex. Util. Code Ann. § 39.102 . During the interim period, the Commission took steps to prepare for the start of competition, including freezing retail rates. See,
e.g., id.
§ 39.052 (freezing retail rates).
In addition, to help smooth the transition to a competitive market, the Commission prepared a report — the 1998 ECOM Report — estimating the potential stranded costs that nine utilities would have at the start of retail competition in 2002.
Cities of Corpus Christi,
188 S.W.3d at 686 . If the 1998 ECOM Report projected that a utility would have stranded costs, the utility was required to engage in steps to mitigate its predicted stranded costs. Tex. Util.Code Ann. § 39.254;
CenterPoint Energy, Inc.,
143 S.W.3d at 88 . To facilitate mitigation, the utilities code provided “a number of tools to an electric utility to mitigate stranded costs.” Tex. Util.Code Ann. § 39.254. These tools allowed a utility “to reduce ... its stranded costs each year” by reducing the net book value of generation assets.
Id.
During the interim period, utilities were required to file annual reports with the Commission detailing any earnings they had that were in excess of their costs.
See id.
§ 39.257 (requiring utility to file report identifying “any positive difference between annual revenues ... and annual costs”). These reports were used to determine whether the utilities were obtaining excess earnings as a result of the frozen utility rates.
CenterPoint Energy, Inc.,
143 S.W.3d at 88 . If a utility’s annual report indicated that the utility had positive earnings for the year, then the utility was compelled to apply the amount of the excess earnings to reduce “the net book value” of the potentially stranded assets. Tex. Util.Code Ann. § 39.254.
After competition began, the Commission was required to perform another ECOM analysis for the utilities sometime before the true-up proceedings in 2004.
See id.
§ 39.201(h). This analysis used updated company-specific information to estimate each utility’s predicted stranded costs.
Id.
If, after performing the calculation, the Commission predicted that a utility would have stranded costs, then the Commission was authorized to facilitate recovery for the stranded costs.
Cities of Corpus Christi,
188 S.W.3d at 686-87 ;
see
Tex. Util.Code Ann. § 39.201(b)(3).
When the Commission performed the second ECOM analysis, it predicted that the Joint Applicants would not have any stranded costs. Essentially, the calculation predicted that the expected market value of the generation assets would exceed the net book value of the assets. As a result, the Commission concluded that mitigation efforts engaged in by Center-Point — namely applying excess earnings to reduce the net book value of the assets— were excessive and would ultimately result in an overrecovery of stranded costs.
27
Consequently, the Commission ordered CenterPoint to refund the excess earnings.
See Cities of Corpus Christi,
188 S.W.3d at 688 . The refund was awarded as credits, called excess mitigation credits,
see id.
at 689 ,
28
that were to be given out over a
*36
seven-year period. Rather than allowing the credits to be given to end-use customers, the Commission concluded that Cen-terPoint should give the credits to retail electric providers, including CenterPoint’s co-applicant Reliant, to reduce the cost of purchasing transmission services.
In addition, the Commission ordered CenterPoint to credit to the retail electric providers 7.5% in interest for the amount of excess earnings retained by CenterPoint that had not yet been transferred as credits. As a result, the ordered credits were basically composed of two parts: (1) an amortized portion of the excess earnings retained by CenterPoint, and (2) interest on the balance of the excess earnings that had not yet been refunded.
Furthermore, the Commission concluded that the retail electric providers could not pass through the value of the credits to their price-to-beat customers because passing through the benefit of the credits would violate the provision of the utilities code prohibiting retail electric providers from charging rates that were different than the price to beat.
See
Tex. Util.Code Ann. § 39.202(e) (providing that retail electric providers can not charge different rates until one or more events occur).
During the 2004 true-up proceeding, it was discovered that the second ECOM estimate was inaccurate and that the Joint Applicants had actually incurred significant stranded costs. As a result, the Commission ordered the utilities to cease crediting to the retail electric providers the value of the excess mitigation and the corresponding interest on the retained earnings. Because the Commission discontinued the credits prior to the seven-year deadline, not all of the excess earnings had been credited to retail electric providers.
In its order, the Commission concluded that the amount of excess earnings that had not been credited to retail electric providers should be used to mitigate the Joint Applicants’ stranded costs. As for the credits already given, the Commission concluded that the Joint Applicants could recover the value of the principal amount of the credits given to retail electric providers, including the co-applicant Reliant, regardless of whether the value of the credit had ultimately been passed through to Reliant’s customers. In other words, even though the Commission had previously prohibited Reliant from passing the benefit of the credits on to its price-to-beat customers, the Commission determined that the Joint Applicants should recover the value of the credits that were not passed through to price-to-beat customers as well as the value passed through to non-price-to-beat customers.
Although the Commission allowed the Joint Applicants to recover the principal amount of the credits, it denied recovery for the interest portion of the credits that the Commission had ordered CenterPoint to award in order to account for the value of the excess earnings that had not yet been credited to retail electric providers. However, the Commission did authorize a different kind of interest recovery. The Commission allowed the Joint Applicants to recover 11.075% in interest on the principal component of the excess mitigation credits actually credited to the retail elec-
*37
trie providers. The recovery was retroactive, meaning that the Joint Applicants were allowed to recover interest from the time that each credit issued. Stated another way, the Commission allowed the Joint Applicants to recover interest on the principal component of the credits that had actually been given to retail electric providers from the time that the credits were given but disallowed recovery for the portions of the mitigation credits previously given that represented interest on the amount of the excess earnings retained by CenterPoint.
The district court upheld the Commission’s determination that the Joint Applicants should recover the principal component of the excess mitigation credits given and 11.075% in interest on the principal component of the credits actually given from the time they were given. However, the district court reversed the Commission’s decision that prohibited the Joint Applicants from recovering the component of the credits given representing interest on the excess earnings not refunded.
Excess Mitigation Credits for Price-to-Beat Customers
On appeal, there appears to be no dispute that the Joint Applicants were entitled to recover as stranded costs the credits given to retail electric providers other than Reliant. What is disputed is whether the Joint Applicants should be allowed to recover for credits given to Reliant. More specifically, the dispute on appeal concerns whether the Joint Applicants should be allowed to recover for the portion of the credits given to Reliant that the Commission prohibited Reliant from passing through to its price-to-beat customers.
The Commission and the Joint Applicants argue that the Commission’s decision to allow the Joint Applicants to recover for the excess mitigation credits given to Reliant was proper.
First, they assert that the issuance of the credits led to an increase in stranded costs and that denying recovery for these costs would result in an under-recovery of stranded costs in violation of the utilities code.
See
Tex. Util.Code Ann. § 39.252(a) (specifying that utility is entitled to recover “all of its net, verifiable, nonmitigable stranded costs”). As support for this assertion, they note that due to the inaccurate ECOM calculation, the Commission ordered CenterPoint to credit the value of the excess earnings to Reliant rather than allowing CenterPoint to use the excess earnings to reduce the net book value of generation assets. Because of this, the Joint Applicants and the Commission argue that the amount of stranded costs increased and that the Joint Applicants should be able to recover for those costs.
Second, they contend that recovery should not be denied even though Reliant was CenterPoint’s co-applicant for stranded-cost recovery. Essentially, they argue that any benefit bestowed upon Reliant should not prevent CenterPoint from recovering because CenterPoint and Reliant are distinct corporate entities. In other words, the benefit given to Reliant did not benefit CenterPoint; to the contrary, the Joint Applicants and the Commission assert that the benefit given to Reliant was to the detriment of CenterPoint.
Third, the Joint Applicants and the Commission contend that recovery should not be denied even though Reliant did not pass the benefit of the credit on to its price-to-beat customers.
29
In essence,
*38
they argue that by retaining the value of the credits, Reliant was only doing what it was ordered to do by the Commission and that the Joint Applicants should not be punished for complying with the Commission’s orders.
30
Alternatively, the Joint Applicants insist that if CenterPoint is unable to recover the value of the credits it gave to Reliant during the true-up reconciliation, it will be unable to recover for this imposed cost in any other manner. In essence, the Joint Applicants argue that there is no statutory provision that allows a utility to transfer the value of credits that it was awarded to one of its affiliates under the circumstances present in this case and therefore insist that there is no way for CenterPoint to reclaim the value of the credits from Reliant. In support of this argument, they argue that the only provision of the utilities code authorizing the transfer of credits between affiliated utilities is inapplicable to this circumstance.
See id.
§ 39.262(e) (requiring retail electric provider to credit its affiliated transmission- and-distribution utility “any positive difference” between price to beat and actual market price). Moreover, the Joint Applicants insist that Reliant has already credited the maximum amount possible under this provision and, therefore, satisfied its statutory obligation.
See id.
We disagree with the assertions of the Commission and the Joint Applicants. Assuming without deciding that Reliant and CenterPoint are completely separate entities, the utilities code treats formerly bundled utilities as related entities for the purpose of stranded-cost reconciliation. For example, the utilities code requires formerly bundled utilities to apply together for the recovery of stranded costs.
See id.
§ 39.262(c). This joint treatment is most pronounced in subsection 39.262(a), which provides, in relevant part, as follows:
An electric utility,
together
with its affiliated retail electric provider and its affili
*39
ated transmission and distribution utility, may not be permitted to overrecover stranded costs....
Id.
§ 39.262(a) (emphasis added).
The plain language of this section demonstrates that all three affiliated utilities are to be considered as a single unit for the purpose of determining stranded-cost recovery. This conclusion is even more apparent when the statute is read in light of the utilities code’s other provisions emphasizing the need for calculating accurate market valuations, mitigating stranded costs, and preventing overreeovery. The reason for the joint treatment is likely the result of the legislature’s recognition that true unbundling into separate, distinct entities would take some time and that there would undoubtedly be resource reallocation among the three utilities for some time after the initial unbundling.
31
The legislature no doubt envisioned the possibility that one utility might seek to recover as a cost a benefit given to its affiliate.
In determining whether the Joint Applicants should recover for the credits, we need not address the propriety of the Commission’s orders: we need only take notice of their effect. CenterPoint obtained excess earnings from its customers, but the Commission ordered CenterPoint to transfer that monetary benefit to Reliant, its co-applicant, and compelled Reliant to retain that benefit. Because Reliant retained the benefit and because joint true-up applicants are prohibited from ov-errecovering as a single unit, it would be improper to allow CenterPoint to recover from end-use customers the amount given to and retained by Reliant. A contrary conclusion would amount to the type of overrecovery sought to be prevented by the utilities code’s treatment of the affiliated utilities as one unit for stranded-cost recovery.
32
For all the reasons previously given, we conclude that the Commission’s decision to allow the Joint Applicants to recover as stranded costs the amount of the excess mitigation credits given to Reliant and not passed on to price-to-beat customers violated subsection 39.262(a) of the utilities code. Accordingly, we reverse the portion of the judgment of the district court affirming that portion of the Commission’s order and remand for further proceedings consistent with this opinion.
Interest
On appeal, the Commission argues that the district court erred when it held that the Joint Applicants were entitled to recover the 7.5% interest on the excess earnings that was credited to the retail electric providers. During the time that the credits were ordered to be made, CenterPoint credited approximately $650 million to various retail providers. Of the $650 million, about $470 million was for excess mitigation, while the remaining $180 million credited was for interest on the excess earnings that CenterPoint had not yet refunded through the credits.
*40
Essentially, the Commission contends that the Joint Applicants should not recover for the interest portions of the credits because the interest portions were not stranded costs as that term is defined.
See
Tex. Util.Code Ann. § 39.251(7) (definition of stranded costs). It argues that the interest credits did not reduce the net book value of any generation assets or constitute a return of excess earnings. On the contrary, it insists that the 7.5% interest rate was imposed to ensure that customers received the time value of the excess earnings retained by CenterPoint. Stated differently, the Commission asserts that the interest was imposed to prevent CenterPoint from receiving the benefit of retaining the value of the excess earnings that it was not otherwise authorized to keep.
We disagree. The Commission’s assertions ignore the fact that, although predicted otherwise, the Joint Applicants did have significant stranded costs and, accordingly, would not have overrecovered had the excess earnings been used to reduce the value of their generation assets. If the ECOM model had accurately predicted that the Joint Applicants were going to have unrecovered stranded costs by the time of the true-up proceeding, Center-Point would have used the excess earnings to reduce the net book value of generation assets to mitigate its stranded costs.
See
Tex. Util.Code Ann. § 39.254. Because the Joint Applicants did in fact have stranded costs and should have been allowed to use the excess earnings to mitigate their stranded costs, the utility customers were not entitled to the time value of the excess earnings.
Due to the Commission’s order, the Joint Applicants were not allowed to use the excess earnings to mitigate their actual stranded costs until after the true-up proceeding. Because this mitigation was delayed, the Joint Applicants were denied the actual mitigation potential of the excess earnings. In other words, the Joint Applicants were prohibited from using the excess earnings to reduce the net book value and were, accordingly, denied the time value of an earlier mitigation.
See id.
To have the same effect as a prior mitigation, the Joint Applicants must be allowed to recover for the interest credited on the retained earnings.
Allowing recovery for the interest credited will place the Joint Applicants in the same position that they would otherwise have been in had the ECOM prediction not been incorrect.
Cf. Drake v. Trinity Universal Ins. Co.,
600 S.W.2d 768, 771 (Tex.1980) (holding that when order requiring payment was reversed, estate was entitled to recover money paid);
Currie v. Drake,
550 S.W.2d 736, 739 (Tex.Civ.App.-Dallas 1977, writ ref'd n.r.e.) (holding that party obtaining benefit through judgment that is later reversed must return benefit to other party).
33
To hold otherwise would unreasonably deny the Joint Applicants the full recovery for credits that they should not have had to give.
Cf. CenterPoint Energy, Inc.,
143 S.W.3d at 92-93 (stating that recovery for actual costs cannot be denied due to inaccurate ECOM prediction).
For all the reasons previously given, we conclude that the Joint Applicants were
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entitled to recover as stranded costs the amount credited to retail electric providers as interest on the excess earnings retained by CenterPoint, except that, for the reasons given in the previous section, the Joint Applicants are not entitled to recover for the interest credited to Reliant that was not passed on to its price-to-beat customers. Therefore, we affirm the portion of the district court’s judgment to the extent that it allowed the Joint Applicants to recover the amount that they credited to retail electric providers other than Reliant as interest on the value of the excess earnings not yet given to the retail electric providers but reverse that portion of the judgment to the extent that it allowed the Joint Applicants to recover the interest credited to Reliant. Accordingly, we remand this issue for proceedings consistent with this opinion.
Investment Tax Credits and Excess Accumulated Deferred Income Tax
During the true-up proceeding, the Commission deducted approximately $146 million from the Joint Applicants’ stranded-cost recovery to reflect the present-day value of various tax benefits given to the Joint Applicants. The district court affirmed this deduction. The Joint Applicants contend that the deduction was erroneous for two reasons. First, they assert that the Commission abused its discretion by making the deductions because the deductions violated certain requirements of the Internal Revenue Service. Second, they argue that even if the reductions were proper, this Court should still find that the Commission abused its discretion by failing to provide a remedy for the Joint Applicants in the event that the Internal Revenue Service later concludes that there was a tax violation.
For reasons unrelated to deregulation, Congress had previously given various companies, including the Joint Applicants, two types of tax benefits: tax credits and deferred taxation.
34
The relevant tax credits are called investment tax credits.
See generally
68 Fed.Reg. 10190 (March 4, 2003) (describing effects of deregulation on investment tax credits). From 1962 to 1986, Congress gave these credits to various utilities to encourage them to invest in new equipment, including generation assets. Unlike a deduction that offsets taxable income, the investment tax credit offsets a utility’s tax liability. Under regulation, although the utility experienced the benefit of the credits early on, it was required to pass the benefit on to its customers over the book life of the asset — a process referred to as normalization.
The deferred taxes relevant in this issue are called excess deferred income taxes. Deferred taxation resulted from Congress’s decision to allow utilities to accelerate the depreciation of various assets and, as a result, pay significantly reduced income taxes.
See Public Util. Comm’n v. GTE-Southwest, Inc.,
833 S.W.2d 153, 166 (Tex.App.-Austin 1992),
rev’d on other grounds,
901 S.W.2d 401 (Tex.1995).
Although the taxable value of the assets was quickly depreciated, the regulatory value of the assets depreciated using a straight-line method.
Id.
Explained another way, for rate-making purposes, the value of the assets was reduced by the same amount each year. The amount of taxes charged to the customers was based on the regulatory value. As a result, the amount of taxes paid by the customers during the first portion of an asset’s expected life was more than the amount of
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income taxes actually paid by the utility.
City of Somerville v. Public Util. Comm’n,
865 S.W.2d 557, 564 (Tex.App.-Austin 1993),
overruled, by Public Util. Comm’n v. GTE-Southwest,
901 S.W.2d 401 (Tex.1995). The resulting difference between the tax assessed and the amount collected from customers for taxes was deposited into an account.
GTE-Southwest, Inc.,
833 S.W.2d at 166 . During the later parts of an asset’s expected life, the amount of taxes paid by the utility was more than the amount collected from the customers.
City of Somerville, 865
S.W.2d at 564. During this period, the balance of the taxes owed that were in excess of those collected from customers were paid out of the account previously mentioned.
The excess deferred income taxes at issue in this case resulted from the reduction of the corporate income-tax rate.
See generally
68 Fed.Reg. 10190 (describing effects of deregulation on deferred income taxes). Before the reduction, the utilities were collecting deferred taxes at a higher tax rate. However, because the tax rate was lowered, the utility would never have to pay the full amount of the deferred taxes collected. The balance of the deferred taxes accrued at the higher rate over the amount accrued at the lower rate constituted the excess deferred income taxes. Utilities passed through the benefits of the excess deferred taxes by utilizing a normalization method.
The Deductions
On appeal, the Joint Applicants dispute the propriety of the Commission’s decision to reduce the amount of stranded costs by the present-day values of the investment tax credits given to them and the excess accumulated deferred income taxes that they accumulated. The Joint Applicants do not dispute that retaining the credits and deferred taxes benefitted them or that their customers were entitled to receive these benefits. However, they do insist that utilities were prohibited from passing the benefits on to customers earlier than allowed by the Internal Revenue Service. In other words, the Joint Applicants contend that utilities were required to pass through the benefits to their customers over the full depreciation schedule of their assets and were not allowed to return the value of the benefits at an earlier time. Furthermore, they argue that passing through the benefits earlier than allowed — an alleged normalization violation — would have exposed a utility to potentially significant penalties.
See
Tax Reform Act of 1986, Pub.L. No. 99-514, 100 Stat. 2146 (stating that normalization method is not satisfied if excess tax reserve is reduced more quickly than allowed);
see also
26 C.F.R. 1.167(l)-1 (stating that assets may be depreciated by straight-line depreciation or by normalization method). Specifically, they assert that a utility that commits a normalization violation could be required to pay back the remaining balance of the credits and be denied the benefit of claiming accelerated depreciation of their assets.
Based on the preceding, the Joint Applicants argue that by offsetting the stranded-cost recovery for the credits and deferred taxes, the Commission has im-permissibly required them to pass through these benefits to their customers earlier than is allowed and, accordingly, forced the Joint Applicants to commit a normalization violation.
As support for these assertions, the Joint Applicants point to several private letter rulings issued by the Internal Revenue Service. These letters were issued to various utilities in response to questions about the effect that deregulation had on a utility’s obligation to pass through the benefits of excess deferred income taxes and investment tax credits and about whether
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passing through the benefits after deregulation would constitute a normalization violation. The letters state that passing the benefits on to customers after deregulation is improper and would violate normalization requirements. Essentially, the letters state that benefit flow-through is only allowed over the traditional regulatory life of an asset and that if the regulatory life of an asset is prematurely terminated through deregulation, the tax benefits may not be passed through to a utility’s customers.
In light of these rulings, the Joint Applicants insist that the Commission’s decision to deduct the present-day value of the investment tax credits and deferred income taxes from the Joint Applicants’ stranded-cost recovery was an abuse of discretion and unreasonable.
We disagree. First, the Commission’s decision to reduce stranded-cost recovery by the amount of the credits and taxes retained seems reasonable in light of the statutory mandate that utilities not be allowed to overrecover during the true-up process.
See
Tex. UtiLCode Ann. § 39.262(a). Utilities were given the benefit of tax credits and the benefit of quickly depreciating the value of their assets while collecting from customers the full regulatory time-value of the assets. Had the industry continued to be regulated, the Joint Applicants would have been required to pass through the benefits on to their end-use customers. Allowing the Joint Applicants to retain these benefits without reducing their stranded-cost recovery by the amount retained would seem to run afoul of the prohibition against overrecovery.
Second, the letters relied upon by the Joint Applicants are private letter rulings, which, by statute, may not be “used or cited as precedent.”
See
26 U.S.C.A. § 6110 (k)(3) (West 2002). In fact, the letters relied on by the Joint Applicants specifically state that the rulings are specifically limited to the taxpayers requesting the rulings.
Third, the Commission based its decision in large part on a rule by -the Internal Revenue Service that was proposed after the issuance of the last letter ruling relied on by the Joint Applicants. The proposed rule would have allowed a deregulated utility to pass through the benefits of the deferred taxes and credits without violating normalization requirements.
See
Application of Normalization Accounting Rules to Balances of Excess Deferred Income Taxes and Accumulated Deferred Investment Tax Credits of Public Utilities Whose Generation Assets Cease to be Public Utility Property, 68 Fed.Reg. 10190, *10190 (proposed March 4, 2003) (to be codified at 26 C.F.R. pt. 1). In particular, the preamble to the rule stated that the benefits should be “flowed through to ratepayers.”
Id.
at 10191. After considering the proposed rule, the Commission, in its order, stated that the proposed rule was more instructive than the letter rulings because the proposal was more recent and because the rule, if adopted, would apply to all utilities, unlike the letter rulings.
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In light of the prohibition against ov-errecovery and the proposed rule, we cannot conclude that the Commission abused its discretion or acted unreasonably when it deducted the present-day value of the deferred taxes and credits from the Joint Applicants’ recovery for stranded costs. This conclusion is further supported by the fact that other states’ utility commissions have concluded that passing through the value of credits and deferred taxes after deregulation does not constitute a normalization violation and the fact that the Joint Applicants’ expert testified that he was unaware of any recent instance in which the Internal Revenue Service concluded that a utility had committed a normalization violation.
See, e.g., DPUC Review of the United Illuminating Co.
's
Divestiture Plan Phase II,
Docket No. 98-10-07, 1999 WL 716484 , 1999 Conn. PUC LEXIS 313, *28-29 (June 9, 1999) (concluding that ratepayers were entitled to benefit of tax credits and deferred taxation);
Application of Penn. Power Co. for Approval of its Restructuring Plan Under Section 2806 of the Pub. Util.Code,
Docket No. R-00974149, 1998 WL 1013699 , *27, 1998 Pa. PUC LEXIS 182, *65-66 (July 22, 1998) (using present-day value of tax credits as offset to utility’s recovery).
For these reasons, we must conclude that the district court properly affirmed the portion of the Commission’s order reducing the Joint Applicants’ recovery by the current value of the tax benefits.
Remedy
In addition to contesting the deduction for credits and deferred taxes, the Joint Applicants also contend that the Commission abused its discretion by failing to include a remedy in its order to account for the possibility that the Internal Revenue Service might later decide that the deduction violated normalization requirements. As support for the idea that the Commission should have fashioned a remedy, the Joint Applicants point to the various private letter rulings discussed previously. They also point to a recent private letter ruling issued by the Internal Revenue Service after oral argument. The letter states that if the Joint Applicants pass through the value of the tax benefits to their customers as part of the deregulation process, the Joint App

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Source: Frix Law Library, https://www.frixlaw.com/law-library/cases/1384317. Public record. Not legal advice.