Centerpoint Energy Houston Electric, LLC and Texas Genco, LP // Cross Gulf Coast Coalition of Cities, Houston Council for Health and Education, City of Houston, Coalition of Cities v. Public Utility Commission of Texas, Office of Public Utility Counsel, Gulf Coast Coalition of Cities, City of Houston, Texas Industrial Energy Consumers, Houston Council for Health and Education, State of Texas, Occidental Power Marketing, L.P.

TEXAS COURT OF APPEALS, THIRD DISTRICT, AT AUSTIN

444444444444444444444444444
ON MOTION FOR REHEARING
444444444444444444444444444

NO. 03-05-00557-CV

Appellants, CenterPoint Energy Houston Electric, LLC and Texas Genco, LP //
Cross 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

v.

Appellees, 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 // Cross-
appellees, Office of Public Utility Counsel, Public Utility Counsel, CenterPoint
Energy Houston Electric, LLC, Texas Genco, LP, and Reliant Energy Services, LLC

FROM THE DISTRICT COURT OF TRAVIS COUNTY, 250TH JUDICIAL DISTRICT
NO. GN500439, HONORABLE JOHN K. DIETZ, JUDGE PRESIDING

OPINION

Our opinion and judgment issued on December 20, 2007, are withdrawn, and the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 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

2
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”). “[E]ach

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

3
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., 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).

4
 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

1
As part of the transition to deregulation and competition, the legislature specified that from
2002 to 2007, retail electric providers were required to charge their residential and small commercial
customers a rate that was 6% less than the price in effect in 1999 under regulation. Tex. Util. Code
Ann. § 39.202 (West 2007); CenterPoint Energy, Inc. v. Public Util. Comm’n, 143 S.W.3d 81, 87
(Tex. 2004). This rate was termed the price to beat in the retail market.

5
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 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

2
For example, a utility may be unable to recoup expenses after building a particular type of
power-generation asset if, due to market conditions, it is possible to generate electricity more cheaply
by using an alternative fuel. In re TXU Elec. Co., 67 S.W.3d 130, 159 (Tex. 2001) (Hecht, J.,
dissenting).
3
The largest component of these stranded costs is “attributable to investments in nuclear
power plants.” Cities of Corpus Christi v. Public Util. Comm’n, 188 S.W.3d 681, 685
(Tex. App.—Austin 2005, pet. filed).

6
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. Util. Code

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

4
The full definition of “stranded costs” reads as follows:

(7) “Stranded cost” means the positive excess of the net book value of generation
assets over the market value of the assets, taking into account all of the electric
utility’s generation assets, any above market purchased power costs, and any deferred
debit related to a utility’s discontinuance of the application of Statement of Financial
Accounting Standards No. 71 (“Accounting for the Effects of Certain Types of
Regulation”) for generation-related assets if required by the provisions of this
chapter. For purposes of Section 39.262, book value shall be established as of
December 31, 2001, or the date a market value is established through a market
valuation method under Section 39.262(h), whichever is earlier, and shall include
stranded costs incurred under Section 39.263.

Tex. Util. Code Ann. § 39.251(7) (West 2007).

7
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 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

5
Section 39.254 reads, in relevant part, as follows:

8
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 nonbypassable

“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

Each electric utility that was reported by the commission to have positive “excess
costs over market” (ECOM) . . . for the amount of stranded costs before full retail
competition in 2002 . . . must use these tools to reduce the net book value of,
otherwise referred to as “accelerate” the cost recovery of, its stranded costs each year.
Any positive difference . . . shall be applied to the net book value of generation
assets.

Tex. Util. Code Ann. § 39.254 (West 2007).

9
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),

.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

10
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)).

6
It is also possible to obtain a negative number when doing this reconciliation. This could
happen because the utility overrecovered for stranded costs during the first step or because market
conditions have increased the market value of the assets over the book value of the assets.
Reliant Energy, Inc. v. Public Util. Comm’n, 101 S.W.3d 129, 137 (Tex. App.—Austin 2003), rev’d
in part sub nom., CenterPoint Energy, 143 S.W.3d 81.

11
 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).

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

7
A utility’s final fuel balance is the difference between the estimated cost of fuel that was
used to set the utility’s rates for the final period of regulation and the actual cost of fuel for that
period. Reliant I, 101 S.W.3d at 137; see Tex. Util. Code Ann. §§ 39.202(c), .262(d) (West 2007).

12
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 CenterPoint, 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

8
Although only CenterPoint and Genco appealed the judgment of the district court, we will
refer to their issues on appeal as the Joint Applicants’ issues for ease of reading.

13
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 prior 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. Second, 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

14
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:

15
Stranded Costs Calculations in Millions of Dollars9
Joint Applicants Commission’s Commission’s
Request Primary Alternate
Holding Holding

Net Book Value Determination
Mitigation Credits $470 $470 $470
Mitigation Credit Interest $180 $0 $0
Construction Costs $147 $147 $147
Other $4,565 $4,565 $4,565

Total $5,362 $5,182 $5,182

Market Value Determination
Utilizing Different Methods $2,908 $3,417 $3,159

Non-reduced Stranded Costs
NBV-MV $2,454 $1,765 $2,023

Deductions
Tax Benefits $0 $146 $146
Stranded Costs Recovered in
Capacity Auctions $0 $378 $378
Commercially Unreasonable
Behavior and Tax Benefits $0 $0 $508
Other $0 $18 $46

Total Deductions $0 $542 $1,078

Net Stranded Costs
SC-Deductions $2,454 $1,222 $945

Interest $539 $121 $68

Stranded Cost Recovery
Net SC + Interest $2,994 $1,343 $1,013

9
The charts included in this opinion are meant to provide an overview and context to the
numbers and calculations at issue in this case. They are not meant to provide an accurate description
of the final true-up results.

16
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
Joint Applicants Commission’s Commission’s
Request Primary Alternate
Holding Holding

Capacity Auction
Auction Results $1,357 $1,357 $1,357

Deductions
Noncompliance $0 $440 $440
Other $0 $26 $26

Capacity Auction True-up
Cap. Auct. - Ded. $1,357 $891 $891

Interest $0 $168 $168

Capacity Auction Recovery
CA True-up + Interest $1,357 $1,059 $1,059

17
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

18
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 meaning 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 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,

19
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

20
(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 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.

10
These same methods are also described in the administrative code. See 16 Tex. Admin.
Code § 25.263 (2007).

21
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(i); 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

22
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 with it the power to control the corporation”). In 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

23
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 Partial-Stock-Valuation Method

In their first issue on appeal, the Joint Applicants contend that the Commission erred

24
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 listed 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).

25
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

26
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).

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.

11
In testimony given before the Commission, one of the Joint Applicants’ witnesses and
other witnesses stated that the distribution to the CenterPoint stockholders was not a “sale” as
required by the partial-stock-valuation method. The necessity of a completed sale to a third party
was also discussed in the portion of the 1998 ECOM report discussing possible methods for
calculating market value. One possible method was called a “spin-down” and involved transferring
generation assets to an affiliated company and distributing stocks of the affiliate to existing
shareholders. Under this method, the utility’s management determines the initial value of the assets.
As a result, “a true initial market valuation” would not occur because the assets were not publicly
traded or offered to third parties. On the contrary, the report stated that the true value would be
established after some time had passed and after “the new shares are traded on stock markets.”

27
 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 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

12
The Joint Applicants also argue that a spin-off on its own can constitute a sale under the
utilities code. In support of this assertion, they refer to two federal cases in which courts held that
a spin-off of stock constituted a sale under the federal Securities and Exchange Act. See
Securities & Exch. Comm’n v. Datronics Eng’rs, Inc., 490 F.2d 250, 253 (4th Cir. 1973) (holding
that spin-off of stock satisfied definition of “sale” or “sell” in federal securities act); Securities
& Exch. Comm’n v. Harwyn Indus., Corp., 326 F. Supp. 943, 953-55 (S.D.N.Y. 1971) (explaining
that spin-off treated as sale requiring registration). However, the cases relied on by the Joint
Applicants are inapplicable to the present case. The statutory scheme at issue in those cases has a
focus on requiring full disclosures in securities transactions, see Nash v. Farmers New World Life
Ins. Co., 570 F.2d 558, 562 n.8 (6th Cir. 1978), not on determining the market value of generation
assets, see Tex. Util. Code Ann. § 39.262(h), (i) (West 2007). See also Rathborne v. Rathborne,
683 F.2d 914, 920 n. 21 (5th Cir. 1982) (stating that conclusion in Datronics that distribution to
stockholders constituted sale applied in enforcement action by Securities and Exchange Commission
but did not apply to private damage action). Moreover, when enacting the statute, the legislature
incorporated the requirements that stock be “spun off and sold.” Tex. Util. Code Ann.
§ 39.262(h)(3). Because both concepts were included, we must presume that the legislature intended
that the phrases impose two distinct requirements and were not mere duplicates of one another. See
USA Waste Servs. of Houston, Inc. v. Strayhorn, 150 S.W.3d 491, 494 (Tex. App.—Austin 2004,
pet. denied) (noting that courts should presume that every word in statute was included for reason).

28
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 overrecover 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

13
Testimony given to the Commission supports this proposition as well. Before the
Commission, one of the Customers’ experts testified that the amount that Genco stock trades for on
the stock market would be artificially reduced if an insufficient level of stock was released for trade.

29
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 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

30
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

14
As part of vertical unbundling, utilities were required to file business-separation plans with
the Commission. When filing their plan, the Joint Applicants suggested an initial public offering
as a means of complying with the partial-stock-valuation method. In addition, during the true-up
proceeding, one of their witnesses testified that an initial public offering would have satisfied the
requirements of the valuation method.
15
In its order approving the Joint Applicants’ business-separation plan, the Commission
noted that the Joint Applicants were going to establish the market value of their generation assets
by having “an initial public offering of approximately 20% of . . . [Genco’s] common stock.”
Tex. Pub. Util. Comm’n, Reliant Energy, Inc. Business Separation Plan Filing Package, No. 21956
(Order on Rehearing) (May 29, 2001).
16
As support for their assertion that the market would not have reacted favorably to an initial
public offering, the Joint Applicants refer to the testimony of one of their witnesses stating that the
energy market in 2002 would not have supported a public offering.

31
 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 impossible 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 spin-offs 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 spin-off 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 spin-off 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

32
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

17
This conclusion is further supported by the testimony of various witnesses before the
Commission stating that the small trading volume of Genco stock actually depressed the value of
Genco’s stock.

33
fails to satisfy this burden, 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,

nonmitigable 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).

18
The Customers also refer to language in the Commission’s order in which the Commission
stated that it was possible to conclude that by failing to establish a market value, the Joint Applicants
were not entitled to recover for their stranded costs.

34
 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 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.

35
 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 CenterPoint 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

36
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 occurring 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.

19
The Commission also expressed a desire for keeping a valuation final when it decided to
limit its estimate of the market value of Genco to the same time interval that would have been used
if the partial-stock-valuation method had been complied with. This decision was no doubt based on
the desire to neither reward nor punish the Joint Applicants for their failure to comply with the
valuation requirements by denying them any benefits or saddling them with any drawbacks resulting
from changes in the marketplace occurring after the time originally selected for the valuation.
20
In its briefs, the Commission also asserts that to employ the sale-of-assets valuation
method, there must be evidence that the sale occurred “in a bona fide third-party transaction under
a competitive offering.” Tex. Util. Code Ann. § 39.262(h)(1) (West 2007). However, it contends
that little evidence was offered to prove that the offer was made under the required competitive
circumstances and that, therefore, the method could not properly be employed.

The apparent purpose behind the competitive showing is to prevent the possibility that a
utility will recover more through the stranded-cost true-up than it is entitled to by employing a low
estimate of the value of its generation assets. In other words, the sales price obtained through a
competitive market environment, unlike a two-party transaction, is less likely to significantly
underestimate the value of the assets. For this reason, employing a competitive sales price will also
decrease the chances that the utility will overrecover stranded costs through the true-up process.

The actual market value used by the Commission was lower than the price offered. For this
reason, the apparent purpose of the statute would seem to have been satisfied despite the lack of
evidence showing sufficient competitive circumstances.

37
 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 exclusio 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,

21
In support of its assertion, the Customers point to language found in the Commission’s
order that stated that it performed a market valuation that was “outside of the methods specified in”
the utilities code.

38
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 recovery, 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. § 39.262(h)(3).

22
It is worth noting that several of the Customers suggested that in light of the fact that the
partial stock valuation could not be employed, the Commission should employ other methods for
determining market value.

39
 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 [C]ommission 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 was not substituting its opinion for a market valuation calculated by

using one of those methods.

40
 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)

41
(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 value.24 Further, they argue that by

using the panel’s report as a basis of estimating market value, the Commission impermissibly made

the panel the final fact-finder for market valuation. Although they acknowledge that, under the

23
It is worth noting that several parties presented alternative valuations calculated by using
methods not considered by the valuation panel. These estimates provided a range of values that were
above and below the amount ultimately chosen by the Commission.
24
In support of this assertion, the Customers point to admissions by the panel that its
valuation was not independently verified and that the actual market value may be “more or less” than
the amount calculated.

42
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.

43
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 their 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 impermissibly 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 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

44
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

25
Furthermore, the terms of the contract between the Commission and the panel members
specified that they were to “reach a conclusion regarding the range of fair values of Texas Genco.”

45
recovery, they had every incentive to participate in the panel’s determination and to provide evidence

supporting their positions.26 Moreover, the 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 Hammack 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

26
In support of their argument that they were denied due process, the Customers rely on
Madden v. Texas Board of Chiropractic Examiners, 663 S.W.2d 622 (Tex. App.—Austin 1983,
writ ref’d n.r.e.). That case is distinguishable. In Madden, the Board created a new definition for
the term “bona fide chiropractic school” but did not make that information known until it detailed
the definition in an order denying Madden the opportunity to take the chiropractic licensing exam.
Id. at 626. As a result, Madden was denied due process because he was unaware of the new
requirements of the definition during his contested case before the Board and was, therefore, unable
to present any evidence regarding those new elements. Id. at 627. In this case, the Commission did
not alter or add additional elements to any definition relevant to the true-up proceeding and,
therefore, did not deprive any party of the opportunity to present evidence regarding the new
elements. Further, the Customers knew that a panel had been convened and that its report would be
an estimation of Genco’s market value.

46
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

47
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 authorized 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

48
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.

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

49
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

50
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 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

51
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).

52
 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 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).

53
 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).

54
 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 CenterPoint—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 seven-year period. Rather than allowing the credits to be given to end-use customers, the

Commission concluded that CenterPoint 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.

27
The difference between the 1998 estimate and the 2001 estimate was the result of an
unforeseen increase in the price of natural gas. Cities of Corpus Christi, 188 S.W.3d at 688 n.5.
28
In Cities of Corpus Christi, this Court concluded that the Commission did not have the
authority to order a refund for over-mitigation before the 2004 true-up proceeding.
188 S.W.3d at 693. Stated differently, this Court concluded that the Commission could not order
utilities to award excess mitigation credits. However, the holding in that case does not affect the
outcome of this appeal because the Joint Applicants were not parties to that case and because the
issues raised in this appeal do not address the propriety of the Commission’s order requiring utilities
to give the credits. In this case, we must simply determine whether the Joint Applicants should
recover for the credits given.

55
 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

56
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

electric 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.

57
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

58
denied even though Reliant did not pass the benefit of the credit on to its price-to-beat customers.29

In essence, 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

29
The Joint Applicants also assert that recovery should not be denied on the grounds that
Reliant retained the benefit of the credits without passing the benefit on to price-to-beat customers
because, starting in 2002, the customers were free to switch to a retail provider not bound by the
price-to-beat restrictions and thereby obtain the benefit of the credits. However, even if the
customers might have been able to obtain the benefit of a partial refund by switching providers, this
does not negate the fact that Reliant retained the value of the portion of the credits attributable to the
then-existing price-to-beat customers.
30
Although acknowledging that Reliant was prohibited from passing the value of the credits
on to price-to-beat customers, the Joint Applicants assert that there is some evidence that the price-
to-beat customers actually benefitted from the excess mitigation credits. Specifically, they contend
that the existence of the credits reduced the price to beat that the customers were charged. The only
evidence offered to support this contention is the testimony of a vice president for Reliant stating that
part of the reason that Reliant did not appeal the Commission’s determination of the price to beat
was because Reliant knew that it would be receiving the excess mitigation credits. Because of this,
the Joint Applicants assert that price-to-beat customers indirectly received the benefit of a lower
price to beat.

Other than these blanket assertions, the Joint Applicants point to no evidence supporting
these claims or demonstrating that the customers actually received a benefit due to the credits or that
Reliant’s decision not to appeal the price-to-beat determination was in fact based on the existence
of the credits. In light of the Commission’s directive that Reliant not pass the value of the credits
on to price-to-beat customers, such general assertions, without more, are insufficient to support the
proposition that the price-to-beat customers benefitted from the credits or justify the conclusion that
the Joint Applicants be allowed to recover for the value of the credits given and retained by Reliant.
See Park Haven v. Texas Dep't of Human Servs., 80 S.W.3d 211, 215 (Tex. App.—Austin 2002,
no pet.) (noting that general description of usual process does not constitute substantial evidence of
what occurred in particular case). Further, it is worth noting that between 2002 and 2003, the Joint
Applicants petitioned the Commission to increase the price to beat that they were authorized to
charge four times and that the Commission agreed to each increase.

59
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 affiliated
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

60
provisions emphasizing the need for calculating accurate market valuations, mitigating stranded

costs, and preventing overrecovery. 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 overrecovering 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

31
The lengthy unbundling process is evidenced by the fact that Reliant had not fully
separated from its parent, unbundled company until 2002.
32
This concern was expressed in a dissenting opinion to the Commission’s order. The
dissent provided, in relevant part, as follows:

To both permit Reliant to retain these [excess mitigation credits] and CenterPoint to
recover the same amount in stranded costs is clearly a duplicative recovery . . . .
...

[T]he Commission is requiring the electric customers in the CenterPoint area to pay
twice for that portion of CenterPoint’s stranded costs. If the recovery of those costs
is continued, CenterPoint, in effect, collects money from its customers, gives that
money to Reliant, and then collects once again from its customers.

61
 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.

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

62
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, CenterPoint 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

33
The Commission argues that the cases holding that a party must return money it collected
under an order that was later reversed are inapplicable to the circumstances of this case due to the

63
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

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

fact that the Commission’s order requiring CenterPoint to make excess mitigation credits was never
reversed. However, while the actual order was not reversed by a court, the Commission ordered
CenterPoint to discontinue making the credits. While not a technical reversal, the effect of the
Commission’s subsequent order is sufficiently similar enough to a reversal by a court to make
reference to the cases appropriate.

64
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

34
Much of the description of these two types of benefits comes from undisputed expert
testimony presented to the Commission.

65
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

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

66
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 impermissibly 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 passing

67
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. Util. Code 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.

68
 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.35

35
In support of their assertions, the Joint Applicants also point to another rule proposed by
the Internal Revenue Service after the Commission issued its order and to a recent private letter
ruling given to the Joint Applicants. See Application of Normalization Accounting Rules to
Balances of Excess Deferred Income Taxes and Accumulated Deferred Investment Tax Credits of
Public Utilities Whose Assets Cease To Be Public Utility Property, 70 Fed. Reg. 75762 (proposed
Dec. 21, 2005) (to be codified at 26 C.F.R. pt. 1). The new proposed rule states that for utilities
deregulated after December 2005, passing through the benefits of deferred taxes and credits would
not violate the normalization requirements. However, the proposed rule further states that the
Internal Revenue Service will follow the terms specified in its prior private letter rulings for the pass-
through of benefits by utilities that were deregulated before December 2005. In a letter filed after
oral argument, the Joint Applicants filed a copy of a private letter ruling recently issued by the
Internal Revenue Service addressed to the Joint Applicants. The letter states that the Commission’s
reductions constitute normalization violations.

Although this subsequent proposal and private letter ruling lend some support to the Joint
Applicants’ arguments, in determining whether the Commission abused its discretion, we must limit
ourselves to reviewing the Commission’s decision in light of the information available to the
Commission at the time that its decision was made. For this reason, the new proposal and letter
ruling have no bearing on the reasonableness of the Commission’s action. Moreover, although the
new rule states that the Internal Revenue Service would apply the terms of its prior letter rulings to
utilities previously deregulated, the proposed rule also states that utilities deregulated before
December 2005 could pass through the tax benefits without violating the normalization requirements

69
 In light of the prohibition against overrecovery 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 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 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

as long as they complied with the terms of the 2003 proposed rule, which allows a utility to pass
through the benefits after deregulation without violating normalization requirements. See 70 Fed.
Reg. at 75764-65.

70
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 Applicants will have

committed a normalization violation.

After receiving a copy of the private letter ruling, the Commission filed a letter with

this Court stating that “the applicable federal-income-tax law is in flux.” Further, the letter provides

that it remains unclear whether the Commission’s reductions will constitute normalization violations

because the proposed Internal Revenue Service rule addressing the propriety of passing through the

tax benefits as part of deregulation has not been finalized. However, the letter also states that “the

new private letter ruling increases the cumulative weight on the side of the [Joint Applicants’]

argument that the Commission’s treatment of the two [tax benefits] might cause a

normalization violation.”

In light of the Internal Revenue Service’s recent letter ruling, the continuing

uncertainty on the issue, “the potential tax impact on the [Joint Applicants],” and the potential

impact on rates, the Commission now asks this Court to remand the remedy issue back “to the

Commission to be re-considered in light of new developments.” Although the Customers support

the Commission’s decision to discount the Joint Applicants’ stranded costs, the Customers state on

appeal that they do not oppose providing the Joint Applicants a remedy in the event the Internal

Revenue Service determines that a violation occurred. We, therefore, reverse the judgment of the

district court to the extent that it affirmed the Commission’s decision to not provide the Joint

71
Applicants with a remedy, and we remand this proceeding back to the district court for proceedings

consistent with this opinion.

Plants Held for Future Use and Construction Work in Progress

Under regulation, utilities were allowed to charge their customers for their operating

expenses. See Cities for Fair Util. Rates v. Public Util. Comm’n, 924 S.W.2d 933, 935 (Tex. 1996).

Operating expenses were generally limited to the expenses resulting from running a functioning

power plant. As a result, utilities were generally prohibited from recovering from current customers

the cost of constructing new power plants and could only recover the costs after a new plant had been

completed. See id. There was one exception to the prohibition against early recovery for

“construction work in progress”: A utility was allowed to recover its construction costs before

construction was complete if it demonstrated that early recovery was “necessary to the utility’s

financial integrity” and that the construction was not “inefficiently or imprudently managed or

planned.” Tex. Util. Code Ann. § 36.054.

In addition to the construction costs, utilities often had to pay other expenses relating

to assets that might not be productive for years to come. Cities for Fair Util. Rates, 924 S.W.2d at

937. For example, to prevent the possibility of having to pay an exorbitant land-purchase price

immediately before construction began, utilities often purchased or rented land years before

construction was scheduled to begin. Id. This type of proactive planning was encouraged by

allowing utilities to recover the acquisition costs even if actual construction did not begin until years

after the utilities obtained rights to the land. See id. These costs were often referred to as costs

related to “plants held for future use.”

72
 In its order, the Commission allowed the Joint Applicants to recover the costs for

plants held for future use and for construction work in progress. The district court affirmed that

decision. On appeal, the Customers contest this decision. The Customers argue that the purpose of

stranded-cost recovery is to allow utilities to recover for costs that would have been recovered had

regulation continued. Based on this proposition, the Customers insist that the Joint Applicants

should not have been allowed to recover the construction and future-use costs because they did not

satisfy the requirements of the statutes governing early recovery for these types of costs under

regulation. In other words, the Customers contend that the Joint Applicants should not recover

because they presented no evidence showing that recovery was necessary to their “financial integrity”

and that construction was not “inefficiently or imprudently planned or managed.” See Tex. Util.

Code Ann. § 36.054.

When making this assertion, the Customers acknowledge that the administrative-code

provision governing true-up proceedings specifies that the net book value of a utility’s generation

assets includes the costs relevant to this issue. See 16 Tex. Admin. Code § 25.263(g)(2) (specifying

what is included in net book value). They further acknowledge that section 36.054 is found in the

rate-making portion of the utilities code, not the stranded-cost-recovery portion. However, they

insist that the requirements of section 36.054 were incorporated into the stranded-cost provisions via

section 39.260, which provides, in relevant part, as follows:

The definition and identification of invested capital . . . that affect the net book value
of generation assets during the freeze period shall be treated in accordance with
generally accepted accounting principles as modified by regulatory accounting rules
generally applicable to utilities.

73
Tex. Util. Code Ann. § 39.260(a) (emphasis added). Essentially, the Customers contend that the

requirements listed in section 36.054 constitute “generally accepted accounting principles as

modified by regulatory accounting rules generally applicable to utilities” and, therefore, must have

been complied with to properly allow recovery. Because the Joint Applicants presented no evidence

regarding the elements listed in section 36.054, the Customers assert that the Joint Applicants should

not have been allowed to recover the value of these construction costs.

We believe that the Commission’s determination that the utilities code allows for the

recovery of the disputed costs is correct and consistent with the relevant statutory provisions for

several reasons.36

First, the Customers’ construction of section 36.054 ignores the unique role that

section had in rate-setting. As discussed previously, utilities were generally not allowed to collect

for construction costs of developing new generation assets until after the construction was complete.

See Cities for Fair Util. Rates, 924 S.W.2d at 935. Section 36.054 provided a mechanism through

which a utility could recover construction costs early but, due to the potential unfairness of charging

current customers for a benefit that they may never receive, limited the circumstances under which

this type of recovery was available. See id. at 936; see also Tex. Util. Code Ann. § 36.054 (limiting

36
As a preliminary matter, we note that the Customers are not contesting whether the
calculated values for construction work in progress and plants held for future use are supported by
substantial evidence; rather, they contend that the values should not have been included in the Joint
Applicants’ net book value because various statutory requirements were not met. In light of this, we
need not address whether the calculated values are supported by the evidence presented to the
Commission. We also note that section 36.054 is entitled “Construction Work in Progress” and
makes no mention of plants held for future use. See Tex. Util. Code Ann. § 36.054 (West 2007).
As a result, the Customers’ arguments concerning the need for complying with section 36.054 seem
to have no applicability to the inclusion of future-use costs in the Joint Applicants’ net book value.

74
circumstances for early recovery because “inclusion of construction work in progress is an

exceptional form of rate relief”). If the utility was unable to prove that the strict requirements of

section 36.054 had been complied with, it was prohibited from recovering at that time, but it was not

prohibited from seeking early recovery of these costs at another rate-setting hearing or ultimately

seeking recovery after construction had completed.

In light of the fact that utilities could eventually recover for these costs even if they

failed to qualify for early recovery, denying recovery for these costs would constitute a denial of a

cost incurred by the Joint Applicants that they would have been allowed to recover for under

regulation: a result that the Customers admit, on appeal, is inappropriate. Furthermore, given that

the true-up proceeding was designed to be a one-time event in which utilities are allowed to recover

their stranded costs, construing the relevant provisions in the manner suggested would forever deny

the utilities the right to recover these otherwise recoverable expenses and would give section 36.054

a punitive effect not contemplated by the legislature when it enacted the statute during regulation.

Such a construction would also violate the utilities code’s mandate that utilities are allowed to

recover “all” of their stranded costs. See Tex. Util. Code Ann. § 39.252.

Second, we see no reason to conclude that section 39.260 somehow incorporates the

directives from section 36.054 into stranded-cost recovery. The requirements listed in section 36.054

do not seem to relate to any type of accounting principles or rules. Rather, the requirements are

geared solely toward a determination of whether a cost may be included in a utility’s rate, not with

defining or describing any particular accounting methodology. Additionally, section 36.054, by its

terms, applies to a “utility’s rate base.” Id. § 36.054. To conclude that section 36.054 applies to true-

up proceedings, we would essentially have to treat a utility’s rate base as synonymous with its net

75
book value—the relevant factor considered in true-up proceedings. However, these concepts are not

equivalent, see id. § 31.002 (definition of rate), and we must presume that the legislature included

both terms in the utilities code for a reason, see Helena Chem. Co. v. Wilkins, 47 S.W.3d 486,

496 (Tex. 2001).

Further, the provision of the administrative code detailing the requirements for

stranded-cost recovery includes the value of construction work in progress and plants held for future

use in the net book value of a utility’s generation assets but makes no mention that a utility must

prove that recovery is necessary for the “utility’s financial integrity” or that the utility did not

“inefficiently or imprudently” plan the construction of the assets. 16 Tex. Admin. Code

§ 25.263(g)(2) (providing that net book value consists of “generation-related electric plant in service,

less accumulated depreciation . . . plus generation-related construction work in progress [and] plant

held for future use”). That rule was adopted in 2001, and no one contested the propriety of

subsection (g)’s inclusion of the disputed costs. See Tex. Util. Code Ann. § 39.001(f) (West 2007)

(requiring party challenging validity of competition rule to file notice of appeal within 15 days after

rule is adopted and published); City of Alvin v. Public Util. Comm’n, 143 S.W.3d 872, 879-80

(Tex. App.—Austin 2004, no pet.) (stating that validity challenges must be filed within 15 days); see

also Tex. Gov’t Code Ann. § 311.023 (specifying that when attempting to ascertain statute’s

meaning, courts may consider agency’s interpretation of statute).

For all the reasons previously given, we conclude that the Commission’s decision to

allow the Joint Applicants to recover as stranded costs expenditures made for construction works

in progress and plants held for future use was reasonable, did not violate any provision of the utilities

code, and complied with the requirements of section 25.263 of the administrative code. Accordingly,

76
we must conclude that the district court properly affirmed the Commission’s decision to

allow recovery for these costs.

Capacity Auction and the Capacity-Auction True-Up

In addition to the stranded-cost true-up, the transition to a competitive market also

involved true-ups for other costs, including a determination of a “capacity-auction award.”37 As part

of the transition, each utility was required to auction off entitlements to its generation capacity.

Tex. Util. Code Ann. § 39.153(a). These auctions were designed to reduce the formerly bundled

utility’s market share and to encourage competition. See Reliant I, 101 S.W.3d at 137.

The various requirements relating to the capacity auctions are found in the utilities

code and in the administrative code. See Tex. Util. Code Ann. § 39.153; 16 Tex. Admin. Code

§ 25.381 (2007). Under both the statute and the rule, formerly regulated utilities were required to

auction off entitlements to “at least 15 percent of” their generation capacity before and after the date

on which customer choice was set to begin. Tex. Util. Code Ann. § 39.153(a) (requiring sale of

entitlements before choice began), (b) (requiring auctions to be conducted until 60 months after

choice begins or earlier date if certain market conditions were satisfied); 16 Tex. Admin. Code

§ 25.381(d) (same as subsection 39.153(a)), (h)(iii) (same as subsection 39.153(b)); CenterPoint

Energy, Inc., 143 S.W.3d at 96. Auctions were to be held four times a year. 16 Tex. Admin. Code

37
We note as a preliminary matter that the legislature was significantly less specific when
defining and describing the capacity auctions and capacity-auction awards than it was when
describing the various methods for determining the market value of a utility’s generation assets and
has thereby, arguably, afforded the Commission more discretion when attempting to accomplish the
legislative directives listed in the statute. See, e.g., Tex. Util. Code Ann. § 39.153(f) (West 2007)
(giving Commission power to adopt rules prescribing capacity-auction procedures).

77
§ 25.381(h)(1)(A)(i). During the auctions, the utilities were obligated to sell entitlements to four

types of capacity products: baseload, gas-intermediate, gas cyclic, and gas-peaking products. Id.

§ 25.381(c)(5), (f), (g). The amount of each type of entitlement that a utility was required to sell

varied depending on the company’s generation assets, but the total amount of the entitlements sold

had to amount to at least 15% of the utility’s total generation capacity. Id. § 25.381(e)(1).

If a utility did not sell all 15% of its capacity products, it might still be viewed as

having complied with this requirement so long as certain other conditions were satisfied. Under the

administrative code, to be deemed compliant, a utility had to “offer[] products in a product category

(for example, gas-intermediate) and successfully [sell], at least, all of the entitlements offered in one

particular month, in that category.” Id. § 25.381(h)(1)(B)(iv).38 In other words, regardless of the

utility’s success in selling a particular type of product in auctions throughout the year, the utility will

be deemed to be in compliance for that product for the entire year if during one month of the year,

the utility is able to sell all of the entitlements to the product that it offered for sale. This deemed-

compliance provision may be applied to a utility’s failure to sell the entitlements to one or more of

its products and, seemingly, even in circumstances in which a utility has failed to sell the necessary

entitlements for all of its capacity products. Stated differently, provided that the utility meets the

deemed-compliance requirements outlined above for each of its products, the utility could be deemed

compliant with the 15% requirement even if it was unable to sell the required number of entitlements

for any of its capacity products. As a result, the provision allows for deemed compliance in certain

38
The following is an example of when this provision would be applicable: if a utility sells
all the required entitlements to three of its products but fails to sell all of the entitlements to the
remaining product, the utility may still be deemed to have complied with the 15% requirement if it
is able to sell all of the entitlements to the non-complying product that are offered in one month out
of the auction year.

78
situations when significantly less than 15% of the entitlements to the utility’s capacity products have

sold. The parties refer to this portion of the administrative code as the “safe-harbor provision.”

If the utility fails to meet the safe-harbor requirements—in other words, it fails to sell

all the entitlements to one or more products offered in one month—the utility may propose

modifications to the auction terms in an attempt to increase the likelihood that the entitlements will

sell. Id. § 25.381(h)(7)(C). The proposals are to be made in notices that the utilities are required to

file with the Commission prior to capacity auctions. See id.; see also id. § 25.381(h)(2)(B) (requiring

utility to file notice of pending auction). In general, these notices specify the auction terms for the

various products. Id. § 25.381(h)(2)(ii). These revisions might include changes to the price of a

product or the type of product auctioned. Id. This provision is called the “alternative safe-harbor

provision” by some of the parties.

Because the utilities code mandates that the utilities auction off a significant portion

of their capacity assets, it also provides the utilities with a method for recovering potential losses in

the event that the sale price at the auction is less than otherwise would have been obtained had the

transition to a non-regulated environment not occurred: the capacity-auction true-up. By authorizing

the true-up, the legislature expressed its concern that a stable market would not exist until several

years after deregulation began and “that distortions and fluctuations in the market price of power

during the first two years of deregulation could harm consumers and generation companies alike.”

CenterPoint Energy, Inc., 143 S.W.3d at 96.

Essentially, a true-up is conducted to determine a utility’s capacity-auction award,

which constitutes the difference between the price that the utility was predicted to obtain by the

79
ECOM model for selling its power on the wholesale market and the predicted fuel costs offset by

the difference between the price that utility actually obtains in the capacity auctions and the utility’s

actual fuel costs. See 16 Tex. Admin. Code § 25.263(i), (l). If the difference between the actual

price obtained and the actual fuel costs is less than the difference between the predicted price and

predicted fuel costs, the utility is allowed to recover the difference. Tex. Util. Code Ann.

§ 39.262(d)(2). The capacity-auction true-up is designed to “guarantee consumers and power

companies that the power company will receive no more and no less than a margin predetermined

by the Commission in 2001 when the ECOM model was run.” CenterPoint Energy, Inc.,

143 S.W.3d at 96.

We now turn to the results of the capacity auctions relevant to this case. In 2002, the

Joint Applicants offered entitlements in all four product categories and ostensibly complied with the

safe-harbor requirements, meaning that during the relevant auction periods, the Joint Applicants were

able to sell all the entitlements offered for one month for each product category.39

39
Although not determinative of this issue on appeal, we note that there is disagreement
about whether the Joint Applicants complied with the safe-harbor rule for 2002. The Customers and
the Commission assert that it was impossible for the Joint Applicants to comply with the safe-harbor
provision for the first half of 2002 because the provision was not enacted until the summer of 2002.
Further, the Customers argue that the Joint Applicants failed to comply with the safe-harbor
provisions for the remainder of 2002. Essentially, the Customers argue that the Joint Applicants
could only be deemed to have satisfied the requirement that they sell all of their products’
entitlements that were offered in a one-month period if the time period under consideration was
extended to include all of 2002 rather than the time that the provision was in effect. The Customers
assert that this type of retroactive compliance is inappropriate under the circumstances of this case.

The Joint Applicants, on the other hand, contend that there was a safe-harbor provision in
effect for all of 2002. Essentially, they argue that the Commission promulgated a much shorter
version of section 25.381 in 2000 that specifically allowed for modification by future orders and that
two subsequent orders added a safe-harbor provision. Tex. Pub. Util. Comm’n, Order Adopting

80
 However, in 2003 the Joint Applicants were unable to satisfy the requirements of the

safe-harbor provision for their gas-intermediate product. After failing to sell entitlements to their

gas-intermediate product at auction, the Joint Applicants informed the Commission of their inability

to meet the safe-harbor requirements. Tex. Pub. Util. Comm’n, Texas Genco, L.P. Request

for Ruling that the Company has Met its Obligation Under PURA § 39.153(a), Docket No. 27744,

(May 5, 2003). In their notice and other documents filed later, the Joint Applicants made proposals

to facilitate the sale of their entitlements.

In their first proposal, the Joint Applicants suggested that the 15% requirement should

be deemed satisfied as a result of other auctions conducted by the Joint Applicants. Id. In addition

to the capacity auctions at issue in this appeal, utilities were authorized to auction entitlements to

New § 25.381, Relating to Capacity Auctions, Project No. 21405, at 64-65 (December 14, 2000); see
Tex. Pub. Util. Comm’n, Proceeding to Address March 2002 and July 2002 Capacity Auctions,
Project No. 24888, at 12 para. 2 (Feb. 7, 2002) (final order adopting capacity-auction-mechanics
document containing safe-harbor provision); Tex. Pub. Util. Comm’n, Proceeding to Implement the
Capacity Auction Rule, Project No. 23774, at 23 para. 2 (Sept. 6, 2001) (final order adopting
mechanics document); see also Tex. Pub. Util. Comm’n, Application of AEP Tex. Cent. Co. & CPL
Retail Energy, LP to Determine True-Up Balances Pursuant to PURA § 39.262 Rates, Docket No.
31056, at 102 (Feb. 16, 2006) (final order specifying contents of safe-harbor rule found in mechanics
document).

We need not determine whether the safe-harbor provision was in effect for all of 2002. To
fully comply with the provision, a utility must satisfy the provision’s requirements for all the years
leading up to the true-up proceeding. Stated differently, if a utility fails to comply with the
requirements in one year, the utility may not employ the safe-harbor rule. We ultimately conclude
that the Joint Applicants failed to comply with the provision in 2003 and, therefore, need not address
whether they complied in 2002. Although we will assume for the sake of argument that the relevant
requirements were satisfied in 2002, we do note that the Commission, in a subsequent proceeding,
has determined that its previous orders did not establish the safe-harbor provision currently found
in the capacity-auction rule. See generally Tex. Pub. Util. Comm’n, Application of AEP Tex. Cent.
Co. & CPL Retail Energy, LP to Determine True-Up Balances Pursuant to PURA § 39.262 Rates,
Docket No. 31056, at 102 (Feb. 16, 2006) (final order).

81
their capacity products in auctions that did not have to comply with the strict requirements of the

capacity auctions. See Tex. Util. Code Ann. § 39.153(d). Relying on this authorization, the Joint

Applicants sold entitlements to their products in private auctions for prices that were higher than the

sale price in the capacity auctions. In light of these additional auctions, the Joint Applicants asked

the Commission to consider the number of entitlements sold in both types of auctions when

determining whether the 15% requirement had been met.40

In their second proposal, the Joint Applicants suggested that additional public

auctions be conducted with modified product specifications. See Tex. Pub. Util. Comm’n, Texas

Genco, L.P. Request for Ruling that the Company has Met its Obligation Under PURA § 39.153(a),

Docket No. 27744, at 1-3 (June 20, 2003) (Texas Genco, L.P.’s Response to order No. 2). After

receiving this proposal, the Commission authorized the Joint Applicants to conduct two additional

auctions. No additional entitlements were sold in the first supplemental auction. In the second

auction, the Joint Applicants were able to sell entitlements to seven of the twenty-eight offered

products, which did not satisfy the requirements of the safe-harbor provision. In this auction, the

reserve price was set at the low price of one penny per kilowatt month.

Because the Joint Applicants were unable to comply with the 15% requirement or the

safe-harbor provision, the Commission concluded that the capacity-auction-true-up formula found

in the administrative code could not properly be employed without modification. See

16 Tex. Admin. Code § 25.263(i)(1). The true-up formula specifies that the capacity-auction award

will be calculated by using the following formula:

40
The Joint Applicants subsequently withdrew this suggestion.

82
 (ECOM market revenues - ECOM fuel costs) - ((capacity auction price x total 2002
and 2003 busbar sales) - actual 2002 and 2003 fuel costs).

Id. To account for the Joint Applicants’ failure to comply, the Commission averaged the price of

all capacity products sold in statutory and private auctions and used this number as the “capacity

auction price” found in the formula. Because the price obtained in the private auctions was higher

than the price used in the statutory auctions, the averaged “capacity auction price” was greater than

the price calculated by the Joint Applicants using only the capacity-auction values. Due to the nature

of the formula, this increase led to a $440 million reduction to the capacity-auction award requested

by the Joint Applicants. The Joint Applicants appealed this determination, and the district court

reversed the Commission’s determination and, accordingly, allowed the Joint Applicants to recover

the full amount they originally calculated.

On appeal, the Customers and the Utility Commission contest the propriety of the

district court’s reversal. In response, the Joint Applicants set forth several arguments as support for

their assertion that the district court’s reversal of the Commission’s decision was proper and that the

Commission’s original reduction was an abuse of its discretion.

In their first set of arguments, the Joint Applicants assert that compliance with the

15% rule or the safe-harbor rule is irrelevant to the capacity-auction true-up formula. As support for

this assertion, they note that the provisions of the utilities code and the administrative code

pertaining to the true-up proceedings do not condition the use of the capacity-auction calculation

upon the sale of a certain number of entitlements. See Tex. Util. Code Ann. § 39.262(d)(2);

16 Tex. Admin. Code § 25.263(i). They also argue that the capacity auction’s 15% requirement and

83
the capacity-auction true-up serve different purposes and should, accordingly, be viewed

independently. They contend that the true-up was designed to give utilities a predictable margin

from the sales of power in 2002 and 2003. See CenterPoint Energy, Inc., 143 S.W.3d at 96 (stating

that true-up essentially guarantees consumers and power companies that power companies will

receive no more and no less than margin predetermined by ECOM model in 2001).

Regarding the capacity auction’s 15% requirement, the Joint Applicants insist that

it was primarily designed to supply retail electric providers trying to compete in the newly

deregulated market with access to much-needed capacity products. See 16 Tex. Admin. Code

§ 25.381(b) (stating that purpose of capacity-auction provision is to promote competition in market

through increased access to generation). In light of these different purposes, the Joint Applicants

urge that it was inappropriate for the Commission to conclude that the failure to comply with the

15% requirement forbade the use of the unaltered true-up formula.

However, for the reasons that follow, we believe that the Commission’s construction

of the relevant portions of the utility code as requiring that the 15% requirement or the safe-harbor

provision be complied with in order to properly apply the true-up equation is correct and consistent

with the relevant statutory language. The Joint Applicants’ construction of the true-up provisions

in the utilities code and the administrative code is too narrow and runs contrary to the canon of

statutory construction requiring courts to construe a provision in light of the entire governing act and

not to read the provision in isolation. See Jones, 969 S.W.2d at 432. While it is true that the true-up

provisions in the utilities code and in the administrative code do not specifically forbid the use of

the capacity-auction-true-up formula due to a utility’s failure to successfully auction off 15% of its

capacity products, both provisions do explicitly refer to the provisions requiring utilities to auction

84
off at least that amount. The true-up provision of the utilities code specifies that a utility is entitled

to the difference between the price of power obtained through “the capacity auctions under Sections

39.153 and 39.156” and the ECOM-power-cost projections. Tex. Util. Code Ann. § 39.262(d)(2).

Section 39.153 requires that a utility auction off “at least 15 percent” of its capacity products. Id.

§ 39.153(a). Similarly, the capacity-auction-true-up provision of the administrative code states that

a utility is entitled to the “difference between the price of power obtained through the capacity

auctions” and the ECOM-power-cost projections and specifically refers to subsection 25.381(h)(1),

which requires that 15% of capacity products be sold or that the safe-harbor provision be complied

with. 16 Tex. Admin. Code §§ 25.263(i)(1), .381(h)(1).

Given the explicit reference to the 15% requirement found in both the administrative

code and the utilities code, we are persuaded that the Commission’s construction of the capacity-

auction-true-up provisions as requiring compliance with the 15% requirement for proper utilization

of the true-up formula accurately reflects the legislature’s intent.

Furthermore, the fact that one of the purposes of the 15% requirement is to ensure that

competitors have access to various capacity products does not preclude the possibility that the

legislature also believed that satisfying the 15% requirement for true-up purposes was also crucial.

As part of the transition to competition, the legislature had to determine the proper amount of

entitlements to be auctioned off that would ensure that a sufficient number of entitlements would be

available to competitors without flooding the market with excess entitlements. As with the partial

stock-valuation method discussed previously, the legislature no doubt chose 15% as the required

amount to be sold as an attempt to ensure that enough entitlements were available to potential

competitors and that enough were sold to provide a relevant approximation of the true market value

85
of the entitlements. In addition, given the fact that utilities are authorized to recover any difference

between the predicted value of the sale of power and that obtained in the capacity auctions, it seems

logical to conclude that the legislature contemplated that customers, as the ultimate payors of a

deficit, would best be served by ensuring that the capacity-auction value reflect, as nearly as possible,

the true value of the capacity products in order to prevent the utilities from being overcompensated

and the customers overcharged.

For all these reasons, we conclude that the failure to comply with the 15%

requirement or the safe-harbor provisions is relevant to the true-up calculation as well as the need

to foster competition.

In their second set of arguments, the Joint Applicants contend that even if compliance

with the 15% requirement or the safe-harbor rule is required for a proper true-up calculation, the

Commission erred by concluding that they did not comply with the safe-harbor provision. See

16 Tex. Admin. Code § 25.381(h)(7)(C). Essentially, they contend that they complied with the safe-

harbor provision because they satisfied the requirements of the alternative safe-harbor provision,

which they insist only requires that a utility propose auction modifications to the Commission. In

other words, they contend that once they proposed modifications for the auctioning of their gas-

intermediate product, the alternative safe-harbor requirements were met, and they should have been

deemed compliant with the 15% requirement.

However, for the reasons that follow, we believe that the Commission’s interpretation

of the safe-harbor and alternative-safe-harbor provisions is correct. The safe-harbor provision

specifically states that the utility “shall be deemed to have met the 15% requirement” if it satisfies

the requirements listed. Id. The alternative safe-harbor provision is found in the sentence

86
immediately following the safe-harbor provision. Although it allows utilities to propose

modifications to the type or price of capacity products auctioned, nowhere in the provision does it

state that merely proposing modifications will constitute compliance with the safe-harbor provision

or the 15% requirement. Id. After employing the traditional rules of construction, we must presume

that this omission from the alternative provision was purposeful. See USA Waste Servs.,

150 S.W.3d at 494.

In addition, the Joint Applicants’ construction of the safe-harbor provision would

essentially nullify the 15% requirement. Under their interpretation, a utility would be deemed

compliant by the mere act of filing a proposed modification regardless of whether the proposal is

reasonable under the circumstances or made in good faith. Even if a utility failed to sell a single

entitlement, it could still be deemed to have complied with the 15% requirement under the Joint

Applicants’ construction so long as it files any proposal to modify the terms of the auction.

Rather than excusing noncompliance with the safe-harbor provision, the alternative

safe-harbor provision seems to allow a utility to apply for another opportunity to comply with the

requirements of the 15% rule or the safe-harbor provision by gaining permission to modify the terms

of an auction in order to increase the likelihood of selling the entitlements and actually meeting the

modified requirements. The Joint Applicants asked for and were given other opportunities to satisfy

the relevant requirements but failed to meet them.

In light of the preceding, we conclude that the Commission’s construction of the safe-

harbor provisions is consistent with the relevant statutes and regulations and accurately reflects the

intent of the legislature. See Fleming Foods of Tex., 6 S.W.3d at 284; Southwestern Bell Tel. Co.,

92 S.W.3d at 441-42.

87
 In their third set of arguments, the Joint Applicants argue that the reduction was

improper because they substantially complied with the safe-harbor provision. Substantial

compliance has been defined as compliance with the “essential requirements of a statute.”

Stratton v. Austin Indep. Sch. Dist., 8 S.W.3d 26, 30 (Tex. App.—Austin 1999, no pet.);

Wentworth v. Medellin, 529 S.W.2d 125, 128 (Tex. Civ. App.—San Antonio 1975, no writ). “A

deviation from the requirements of the statute which does not seriously hinder the legislature’s

purpose in imposing the requirement is substantial compliance.” Stratton, 529 S.W.2d at 31. In

light of the preceding authority, the Joint Applicants insist that even if they did not fully comply with

the relevant requirements, their actions were enough to constitute substantial compliance with the

relevant statutes and rules.

We do not agree with the assertion that selling all of the entitlements to the gas-

intermediate product for one month was not an essential requirement for satisfying the safe-harbor

provision, nor do we believe that deeming utilities compliant with the 15% rule when they have not

met the significantly reduced requirements of the safe-harbor provision would not seriously hinder

the purpose of the statute and the rule. The legislative goal in enacting the relevant statutes was to

have the utilities comply fully with the 15% requirement, not a safe-harbor rule fashioned by the

Commission. Moreover, the use of the phrase “at least” in the utilities code is some indication that

the legislature thought of 15% as the absolute minimum that needed to be sold in order to properly

estimate the value of the entitlements and that it actually preferred that a larger amount be sold. See

Tex. Util. Code Ann. §§ 39.153(a), .262(d). It is against this ultimate legislative goal, not the

satisfaction of the safe-harbor rule, that substantial compliance must be measured. During the

88
auctions in 2002 and 2003, the Joint Applicants only auctioned off 10% of Genco’s capacity, much

less than the 15% required by statute.

Further, the Joint Applicants’ argument ignores the relationship between the 15%

requirement and the safe-harbor provision. In interpreting and enforcing the relevant utilities code

provision and in recognition of the possibility that full compliance may not always be possible, the

Commission promulgated the safe-harbor provision, allowing a utility to be deemed compliant with

the capacity-auction requirements even though the utility sold less than 15% of its capacity products.

See 16 Tex. Admin. Code § 25.381(h)(7)(C). Essentially, the Commission made a determination

of what will constitute substantial compliance with the legislative goal. Given that this substantial-

compliance provision allows utilities to be deemed compliant even though their actions fall far short

of the legislative goal, it is logical to require that compliance with the safe-harbor provision be near

absolute in order to achieve, as much as possible, the desired legislative mandate. Further, given the

Commission’s expertise in the deregulation process, we see no reason to override its determination

of what constitutes substantial compliance by creating our own interpretation of when the 15%

requirement will be deemed to have been substantially complied with.

Despite obtaining permission to hold two additional auctions for their gas-

intermediate product, the Joint Applicants were still able to sell only seven of the twenty-eight

entitlements that they were required to sell to be deemed compliant under the safe-harbor provision.

In light of the preceding, we cannot conclude that the Joint Applicants substantially complied with

the relevant requirements.41 Therefore, we conclude that the Commission correctly determined that

41
The Joint Applicants also refer to a federal case as support for their assertion that they
substantially complied with the relevant statutes and rules. See Estate of McAlpine v. Commissioner,

89
the Joint Applicants did not comply with either the 15% requirement or the safe-harbor provision.

In their fourth set of arguments, the Joint Applicants argue that it was improper to

deny them the full amount of the capacity-auction award that they requested because the failure to

sell entitlements was largely due to two factors outside of their control: (1) actions taken by the

Commission, and (2) the lack of a viable market for gas-intermediate products. Specifically, they

note that it was the Commission that specified the capacity products to be sold at auction and the

minimum auction price. See generally 16 Tex. Admin. Code § 25.381. Further, they argue that the

lack of a viable market was demonstrated by the facts that they were unable to sell the capacity

products even at prices that were significantly lower than first authorized by the Commission and

that other utilities were also unable to sell their gas-intermediate product during the relevant time

period. They also contend that their ability to sell the entitlements in a public auction was

significantly hampered by the fact that Reliant, CenterPoint’s largest potential purchaser, was

statutorily prohibited from participating in the public auctions because it was an affiliated company.

See Tex. Util. Code Ann. § 39.153(c) (prohibiting affiliates from purchasing entitlements in

public auctions).

968 F.2d 459 (5th Cir. 1992). In particular, they highlight that the court in McAlpine stated that
“substantial compliance is achieved where the regulatory requirement at issue is unclear and a
reasonable taxpayer acting in good faith and exercising due diligence nevertheless fails to meet it.”
Id. at 462.

Without deciding whether that is the proper standard for determining substantial compliance,
we note that prior to making the cited statement, the court in McAlpine expressly stated that it was
not “attempting to announce a rule applicable in all cases.” Id. Moreover, in that case the relevant
requirements were unclear. There is no indication in the record that the Joint Applicants were
unclear about how to satisfy either the 15% rule or the safe-harbor provision. On the contrary, given
their back-and-forth exchanges with the Commission regarding the sale of capacity products, it is
clear that the Joint Applicants were aware that they had not satisfied either set of requirements.

90
 We disagree with this line of reasoning. We cannot take umbrage with the

Commission’s actions because by specifying what products would be sold and for what minimum

amount, the Commission was doing exactly what the legislature instructed it to do. The utilities code

required the Commission to develop rules “that define the scope of the capacity entitlements to be

auctioned” and that “state the minimum amount of capacity that can be sold at auction as an

entitlement.” Id. § 39.153(e). Further, the utilities code required the Commission to adopt rules

“that prescribe the procedure for the auction,” including designating “which generation units or

combination of units are offered for auction” and establishing “an opening bid price.” Id.

§ 39.153(f).42 Moreover, although they express dissatisfaction with the Commission’s actions on

appeal, the Joint Applicants have failed to demonstrate that they objected to the products or the price

specified in the Commission’s rule within the time period authorized by statute. See id. § 39.001(f)

(specifying time that party has to challenge validity of rule).

Furthermore, the fact that Reliant was prohibited from purchasing the products at the

auction cannot excuse noncompliance with the requirements of the utilities code or the

administrative code. The provisions relating to the capacity auctions, like with stranded costs, occur

in the context of deregulation, under which a former monopoly was required to separate into distinct

companies with the ultimate goal of developing a competitive retail market. Id. §§ 39.001, .051(b).

42
The Joint Applicants also insist that by specifying any minimum price rather than allowing
completely open bidding, the Commission may have discouraged sales during months with low
demand and may have discouraged buyers from bidding. However, other than referring to articles
stating that reserve or minimum prices reduce the probability of a sale at an auction, the Joint
Applicants refer to no evidence that the simple act of setting a minimum price of any kind would
necessarily and detrimentally impact the auction of capacity products, nor do they explain why that
negative effect would only have been present in the sale of gas-intermediate entitlements and not in
the sale of the other entitlements. In addition, their argument again ignores the fact that it was the
legislature, not the Commission, that determined that setting minimum auction prices was necessary
and beneficial to the capacity auction. See Tex. Util. Code Ann. § 39.153(f) (West 2007).

91
Given the common origin of affiliated companies, the legislature no doubt concluded that the

exclusion of affiliated companies was necessary to ensure that non-affiliated companies trying to

enter the market were able to purchase the capacity products necessary to compete and that their

entrance into the market was not hampered by the possibility of improper dealings between

affiliated companies.

In addition, we must presume that when the legislature enacted the statutory provision

excluding affiliated companies from public auctions, it was aware of and fully considered the

possibility that its choice might hamper the ability of utilities to sell their entitlements. It is not the

place of this Court to re-weigh the factors relevant in this type of public-policy decision, and we will

not thwart the will of the legislature by allowing the exclusion of affiliated companies to justify

noncompliance with the 15% requirement or the safe-harbor rule.

Finally, the fact that there apparently was little market for the gas-intermediate

product actually supports the Commission’s decisions rather than undermines them as alleged by the

Joint Applicants. It is apparent from the fact that the Joint Applicants were able to sell the gas-

intermediate product in private auctions that the market value of this product was not zero.

However, for whatever reason, the public auctions failed to adequately reflect an accurate market

value for the products. In light of the preceding and the fact that one of the purposes of the capacity-

auction true-up is to ensure that utilities receive no more than they were predicted to obtain through

the sale of power, CenterPoint Energy, Inc., 143 S.W.3d at 96, the Commission’s decision to

determine a more accurate market value was reasonable.

In their final set of arguments, the Joint Applicants contend that the actual method

used by the Commission to determine the capacity-auction award was improper. In essence, they

92
argue that the method employed by the Commission reduced their recovery by too great an amount

when compared to the relatively small amount by which they failed to comply with the safe-harbor

provision. They argue that if they had sold all the entitlements offered in the final auction, the

additional recovery would have amounted to only $5,250.43

Although the Joint Applicants’ framing of their argument initially appears

compelling, we cannot agree with their characterization of the reduction. The situation presented

in this issue is similar to the one presented in the market valuation of the Joint Applicants’

generation assets. The relevant rule and statutory provision assume that the utility will comply with

the 15% requirement or with the safe-harbor provision, and neither one addresses the situation of

noncompliance. As a result, the Commission was caught between a statutory mandate requiring that

utilities recover for their capacity-auction costs and the Joint Applicants’ noncompliance with the

requirements necessary for determining an accurate award. For all the reasons that we concluded

that the Commission had the implied authority to develop an alternative market-valuation method,

we must also conclude that the Commission has the implied power to develop an alternative means

for estimating the “capacity-auction price” to be used in the true-up calculation when the relevant

statutory and rule requirements have not been satisfied.44

43
This figure is based on the minimum auction price ($0.01 per kilowatt month), the size
of the entitlements (25000 kilowatt months per entitlement), and the 21 additional entitlements that
would have been sold.
44
Otherwise, the Commission would have been forced to choose between ignoring the issue
of the Joint Applicants’ noncompliance with the statute completely or strictly enforcing the statutory
requirements, thus depriving the Joint Applicants of the $1.059 billion capacity-auction recovery that
the Commission allowed under its alternative calculation.

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 Moreover, when determining the method for calculating the value of the capacity-

auction price, the Commission logically looked to the private auctions to help estimate the value of

the entitlements in a public auction. This decision seems particularly appropriate given the relative

success that the Joint Applicants had in auctioning off the entitlements in the private auctions.

Furthermore, the method chosen by the Commission was based on the testimony of a witness

testifying before the Commission and was supported by substantial evidence.

Additionally, the Joint Applicants’ characterization of the disparity between their

requested award and the award determined by the Commission fails to address significant, relevant

factors that led to the large disparity. The Joint Applicants were instructed to sell a certain amount

of entitlements to each of its four products. The total number of entitlements was supposed to

constitute at least 15% of the Joint Applicants’ total number of capacity products. However, in 2002

and 2003, the Joint Applicants failed to sell the required amount of entitlements for any of their

products, meaning that less than the statutorily required 15% was sold. Although they may have met

the lower sale requirements of the safe-harbor provision of the administrative code for some of their

products, the Joint Applicants still sold significantly fewer entitlements than was required under the

utilities code. As a result, the capacity-auction award calculated by the Joint Applicants was based

on the sale of a number of entitlements deemed insufficient by the legislature for that purpose.

Further, the Customers provide an uncontradicted explanation for how the failure to

sell the required amount of any of the capacity products and how the sale of so few of the gas-

intermediate products in particular led to an overestimate of the capacity-auction costs by the Joint

Applicants.45 The Customers assert that the true-up formula requires the sale of the full 15% of

45
Although the Joint Applicants do not specifically contest the Customers’ characterization
of the formula and its functioning when less than 15% of a utility’s entitlements have sold, the Joint

94
entitlements or, alternatively, the sale of enough entitlements to satisfy the safe-harbor rule in order

to obtain a valid result. Essentially, the Customers argue that when enough of the entitlements have

been sold, the formula is able to properly compare the revenue from the sale of capacity products

with the fuel expenses associated with those products. However, they aver that when an insufficient

amount of entitlements is sold, the necessary comparison of revenue to fuel expense is no longer

possible because the incurred fuel expense will have no counterpart for comparison.

In this case, the Customers insist that the insufficient sale of entitlements to the gas-

intermediate product meant that the revenue component of the capacity-auction price was determined

primarily by the prices for baseload products, which are relatively inexpensive when compared to

the other capacity products, while the expense calculation was heavily weighted by the higher fuel

expenses associated with the other non-baseload products. As a result, the Customers insist that the

capacity-auction price was artificially lowered by the inclusion of significant expenses without

accompanying revenue. The Joint Applicants actually alerted the Commission to the possibility that

the capacity-auction price might be lowered in this manner when they asked the Commission to

consider the number of sales in the private and public auctions in its determination of whether the

15% requirement had been met. Tex. Pub. Util. Comm’n, Request for Ruling that Texas GENCO,

LP has Met Its Obligation Under PURA § 39.153(a), Docket No. 27744 at 6 (May 5, 2003). In their

filing, the Joint Applicants warned the Commission of the potential negative effects of selling a

Applicants do insist that the Customers may not raise this argument on appeal because it amounts
to an unauthorized challenge to the true-up rule. We disagree with the Joint Applicants’ assertion.
The Customers are not contesting the propriety of the rule when all the necessary requirements have
been met—an assertion that they arguably would have been unable to bring in this appeal. Rather,
they contest the Joint Applicants’ unmodified use of the formula when the necessary requirements
have not been met.

95
disproportionate share of baseload products and stated that the sale of more baseload products would

“lower the ‘capacity auction price.’”46

In light of the preceding, we must conclude that the method employed by the

Commssion for calculating the capacity-auction award was reasonable and consistent with the

relevant statutory provisions. Further, for all the reasons given in this section, we conclude that the

Commission did not abuse its discretion or act arbitrarily when it performed the modified capacity-

auction calculation.47 Accordingly, we conclude that the district court improperly reversed the

portion of the Commission’s order reducing the Joint Applicants’ capacity-auction recovery.

Carrying Costs

During the true-up proceeding, the Commission determined that the Joint Applicants

were entitled to recover $168 million as interest or “carrying costs” on the capacity-auction award,

and the district court affirmed this decision. In three sets of arguments, the Customers contest this

decision and argue that the Commission exceeded its authority by allowing this type of recovery.

First, they argue that no provision of the utilities code authorizes the Commission to

award carrying costs on a capacity-auction award. In a similar assertion, the Customers argue that

there is no authority for the proposition that a utility has any right to a capacity-auction award before

46
In its final order, the Commission characterized this effect as “an unacceptable downward
bias in the capacity auction price,” which it concluded caused “an overstatement of the capacity-
auction true-up amount.”
47
It is worth noting that unlike in the stranded-cost issue, the Customers and the Utility
Counsel do not argue on appeal that the Joint Applicants were not entitled to recovery for capacity-
auction costs despite their failure to satisfy the fifteen-percent requirement or the safe-harbor
requirements.

96
the amount of the award is determined in a true-up proceeding, making the carrying-cost

award improper.

We disagree with the Customers’ assertions. The relevant provision for capacity-

auction recovery is found in subsection 39.262(d), which authorizes a utility to recover “the net sum

of . . . any difference between the price of power obtained through the capacity auctions . . . and the

power cost projections that were employed for the same time period in the ECOM model.”

Tex. Util. Code Ann. § 39.262(d). In other words, the provision specifies that a utility is entitled to

recover the difference between the predicted price of power and the actual amount obtained in the

capacity auctions occurring in the years prior to the true-up. While it is true that this provision does

not contain the phrase “carrying costs,” the Commission nevertheless concluded that the Joint

Applicants would not fully recover unless they were allowed to recover the time value (carrying cost)

associated with the delay between when the cost was incurred and when it was finally calculated.

For the reasons that follow, we believe that the Commission’s interpretation of the

utilities code is correct. First, the Commission’s construction is supported by prior precedent

concerning the recovery of carrying costs. Assertions that are similar to those made by the

Customers were presented to the supreme court in a rule challenge to a previous version of

subsection 25.263(l) of title 16 of the administrative code. See generally CenterPoint Energy, Inc.,

143 S.W.3d 81. In CenterPoint Energy, Inc., the supreme court had to determine the validity of a

rule promulgated by the Commission that allowed utilities to recover interest on their stranded costs

but limited the interest recovery to the time after a final true-up order was issued. Id. at 83. Despite

the fact that the relevant true-up provision made no mention of interest or carrying costs, the supreme

97
court concluded that the rule was inconsistent with the governing statutory scheme because it did not

allow for the recovery of more carrying costs. Id. at 84; see also id. at 89 (stating that “[t]he only

explicit reference to carrying costs on stranded costs appears in a section of the Act regarding

securitization,” not true-up recovery). Essentially, the supreme court concluded that to comply with

the mandate that a utility fully recover, stranded costs are to be determined from the date that

competition first began. See id. at 87. Stated differently, the supreme court concluded that utilities

are entitled to recover the value of these costs from the time that they are incurred, not just from the

time that they are calculated. Because the rule did not allow the utilities to recover interest from the

first day of competition, the supreme court concluded that the relevant portion of the rule was

invalid. Id. at 84.48 This same rationale applies with equal force to the situation presented

in this appeal.

Second, because the capacity-auction award was not calculated until the true-up

proceeding, the Joint Applicants’ end-use customers were given the benefit of the time value of

retaining the capacity-auction award until the true-up: a benefit for which they should be required

to compensate the Joint Applicants. Cf. Phillips Petroleum Co. v. Stahl Petroleum Co., 569 S.W.2d

480, 485 (Tex. 1978) (holding that, under equitable principles, party may recover interest on money

that rightfully belonged to that party but was used by another).

Finally, the overall legislative mandate that utilities recover the expenses that they

incur as a result of the transition to a competitive market would seem to require the Commission to

48
In 2006, the Commission promulgated the current version of the rule, which requires that
stranded costs be determined as of the first day of competition. 16 Tex. Admin. Code
§ 25.263(l)(3) (2007); see 31 Tex. Reg. 5603 (2006).

98
award utilities the time value associated with the delay in recovering the capacity-auction award.49

In light of the preceding, we must conclude that the Commission’s interpretation of

the capacity-auction provisions of the utilities code is consistent with the relevant statutory

provisions and accurately reflects the intent of the legislature. We see no discernable difference

between recovery for capacity-auction costs and stranded-cost recovery that would warrant a decision

completely at odds with prior precedent, nor do we see any legitimate reason for limiting the Joint

Applicants’ capacity-auction interest recovery by using the date that the capacity-auction award was

calculated rather than the date that the deficit from the capacity auctions was actually incurred.

In their second set of arguments, the Customers contend that recovery for carrying

costs was inappropriate because the Commission’s true-up rule does not specifically authorize this

type of recovery for capacity-auction awards. See 16 Tex. Admin. Code § 25.263(i). In light of this,

they further assert that the Joint Applicants have waived any right to seek this recovery because they

did not contest this omission from the rule in the time allowed by statute. See Tex. Util. Code Ann.

§ 39.001(f) (specifying period of time in which party may contest rule adopted by Commission).

We disagree for two reasons. Although subsection (i), which is entitled “True-up of

capacity auction proceeds,” does not specifically address carrying costs on capacity-auction awards,

a later subsection seems to allow this type of recovery. See 16 Tex. Admin. Code § 25.263(i), (l).

49
The Customers contend that, as utilities, the Joint Applicants bore the risk of delay in
recovering their money under regulation. Reliant I, 101 S.W.3d at 147 (stating that “[n]ormal
‘regulatory lag’ is considered to be an element of risk borne by a utility”). However, in light of the
fact that the true-up proceeding was designed to smooth the transition from regulation to competition
and in light of the strong legislative dictates mandating that utilities be made fully whole by the true-
up procedures, we must conclude that it is inappropriate in this case to assign that risk to the Joint
Applicants.

99
Subsection (l) specifies that a utility “shall be allowed to recover, or shall be liable for, carrying costs

on the true-up balance.” Id. § 25.263(l). When defining what constitutes the “true-up balance,” the

code includes the “[c]apacity auction true-up calculated under subsection (i).” Id. As a result, by

its terms, section 25.263 requires the recovery of carrying costs on a capacity-auction award.

Even assuming that subsection (l) does not apply, we would still conclude that the

recovery of carrying costs was appropriate. Although the subsection relied on by the Customers does

not specifically allow for the recovery of carrying costs, the subsection does not expressly prohibit

their recovery either. See id. § 25.263(i). In light of the absence of an explicit prohibition and in

light of the fact that the recovery is consistent with the relevant statutes, we would appropriately

defer to the Commission’s interpretation. See Ackerson v. Clarendon Nat’l Ins. Co., 168 S.W.3d

273, 275 (Tex. App.—Austin 2005, pet. denied) (stating that “[a]n administrative agency’s

interpretation of its own rules is entitled to great weight and deference”).

In light of the fact that carrying-cost recovery is consistent with the utilities code and

the administrative code, we cannot conclude that the Commission exceeded its authority by allowing

the Joint Applicants to recover carrying costs on their capacity-auction award.

Finally, the Customers assert that by giving the Joint Applicants carrying costs, the

Commission impermissibly allowed the Joint Applicants to obtain a double recovery. In making this

argument, the Customers note that the Commission based its decision to allow for carrying-cost

recovery largely on the testimony and recommendation of a Commission staff witness, Darryl

Tietjen. In his testimony, Tietjen recommended allowing the Joint Applicants to recover interest on

the capacity-auction award in order to make them whole. In addition, Tietjen also testified that the

100
Joint Applicants should recover a “return” on the Joint Applicants’ capital expenditures for 2002 and

2003. The Customers contend that the “return” is simply interest and that it was therefore

unnecessary and improper for the Commission to allow the Joint Applicants to recover two

interest awards.

We disagree. Although both awards are essentially interest awards, they serve very

different purposes. Under regulation, when establishing a utility’s rate, the Commission was

required to set a rate that would allow “the utility a reasonable opportunity to earn a reasonable

return on the utility’s invested capital used.” Tex. Util. Code Ann. § 36.051 (West 2007); see

Central Power & Light Co., 36 S.W.3d at 552-53. In light of this “guaranteed return” provision, the

Commission awarded the Joint Applicants a return on their capital expenditures made

before the true-up.50

The carrying-cost award, on the other hand, serves an entirely different purpose. It

was issued to account for the delay between the time that the Joint Applicants incurred capacity-

auction costs and the time that the costs were fully calculated and recovery could begin. It

reassigned the time value of the award to the Joint Applicants rather than their end-use customers:

a benefit we previously concluded that the Joint Applicants were entitled to recover.

The fact that these two recoveries are distinct is also highlighted by the fact that the

Joint Applicants would have been entitled to the return even if they were not entitled to the interest

50
In a single sentence, the Customers assert that there “is no statutory basis for assuring [the
Joint Applicants] a guaranteed return during 2002 and 2003, after regulation had ended.” However,
the whole thrust of their argument is that the carrying cost award, not the return, was improper.
Moreover, although the utilities code does not specify that a utility is entitled to this guaranteed
return during the transition period, many of the reasons that led us to conclude that an award of
carrying costs was proper would also seem to have equal applicability here.

101
award. Stated another way, if the capacity-auction award had been given to the Joint Applicants at

the time that the cost was incurred, there would be no need to award carrying costs because there

would have been no delay, but the Joint Applicants would still have a right to recover a return on

their investments.

In light of the independent nature and distinct purposes of the awards, we must

conclude that the Commission did not exceed its authority by allowing the Joint Applicants to

recover both awards. Therefore, we conclude that the district court properly affirmed that portion

of the Commission’s order.

Depreciation Expenses

In their final issue on appeal, the Joint Applicants complain about a reduction that the

Commission made to their stranded-cost recovery. In its order, the Commission reduced the Joint

Applicants’ award by $378 million. This deduction was based on the Commission’s determination

that the Joint Applicants recovered a portion of their stranded costs through the auctioning off of

entitlements to their generation assets in the capacity auctions and through the corresponding

capacity-auction true-up award. Specifically, the Commission concluded that through the capacity-

auction process and true-up, the Joint Applicants were able to recover for the depreciation to their

generation assets in 2002 and 2003. Because a utility’s stranded-cost recovery ensures that a utility

will be awarded, among other things, the value of the depreciation to its assets that would ordinarily

have been recovered over the life of the assets under traditional regulation, the Commission

concluded that the Joint Applicants’ stranded-cost recovery already included recovery for

depreciation for the 2002-2003 period. Accordingly, the Commission determined that allowing the

102
Joint Applicants to recover the full amount of both awards amounted to an overrecovery of stranded

costs. Consequently, the Commission reduced the Joint Applicants’ stranded-cost recovery by the

amount of depreciation recovered through the capacity-auction award.51

In attacking the Commission’s reduction, the Joint Applicants essentially employ

three sets of arguments. First, they argue that the capacity-auction true-up does not provide for a

return of stranded costs. Second, they contend that even if it does, the Commission does not have

the authority to reduce their stranded costs to account for that recovery. In other words, they insist

that regardless of whether they recovered some of their stranded costs through the capacity-auction

true-up, the Commission does not have the authority to reduce a utility’s stranded-cost award.

Finally, in attacking the Commission’s reduction, the Joint Applicants pose a hypothetical

comparison between the recoveries of two different utilities and insist that this comparison

demonstrates that the Commission’s interpretation of the relevant statutes will lead to inequitable

and arbitrary results.

The Capacity-Auction Recovery Includes a Partial Recovery for Stranded Costs

In their first set of arguments, the Joint Applicants argue that the Commission’s

reduction was erroneous because the capacity-auction true-up and the stranded-cost true-up provide

independent sources of recovery and, more importantly, because the capacity-auction process does

not provide for a return of stranded costs. In light of this, the Joint Applicants insist that stranded

costs are completely irrelevant to a utility’s capacity-auction recovery. As support for these

51
In its order, the Commission conceded that neither the utilities code nor the administrative
code authorizes a reduction to a utility’s capacity-auction true-up award to prevent an overrecovery
of stranded costs. Accordingly, the Commission reduced the stranded-cost award rather than the
capacity-auction true-up award.

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propositions, the Joint Applicants rely heavily on our Reliant I opinion in which we stated that

stranded costs and the other true-up items are distinct concepts treated differently by the utilities code

and that the legislature chose not to include capacity-auction recovery “in its definition of stranded

costs or to incorporate [that recovery] into the methods it prescribes for calculating stranded costs.”

101 S.W.3d at 140.

For the reasons that follow, we disagree with the Joint Applicants’ assertions. The

supreme court previously cautioned that the design of the capacity-auction true-up might allow

utilities to recover a portion of their stranded costs. See CenterPoint Energy, Inc., 143 S.W.3d 81.

In CenterPoint Energy, Inc., the supreme court was faced, in part, with determining the propriety of

a rule that allowed utilities to recover interest on stranded costs from the date of the final true-up

order rather than the first day of deregulation. Id. at 83. Although the issue of whether utilities may

recover portions of their stranded costs through the capacity auctions and true-ups was not before

it at the time, the supreme court commented that:

[T]he capacity auction true-up procedure set forth in the [utilities code] may include
a component for return of or on stranded costs in 2002 and 2003.

...

What can be gleaned from the record in this proceeding is that some portion of the
margin that results from the capacity auction true-up may contain a component that
allows a return of or on stranded costs.

...

Based on the record before us it appears that the design of the capacity auction true-
up may have permitted generation companies to recover during 2002 and 2003 at
least a portion of their fixed costs, including stranded costs.

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Id. at 84, 87 (emphases added); see also Reliant I, 101 S.W.3d at 140 (noting that relationship

between capacity-auction costs and stranded costs was closer than relationships between stranded

costs and other true-up items). Although the opinion was primarily concerned with the recovery of

interest, the supreme court’s use of the word “of” in the phrase “whether proceeds from a capacity

auction true-up had a component for return on or of stranded costs” indicates that the supreme court

believed that a capacity-auction award might include a portion of a utility’s stranded costs.

When making these comments, the supreme court no doubt recognized the common

purpose of the two true-ups. The overall purpose for enacting the various true-up statutes was to

facilitate the transition to a deregulated market by enabling utilities to “recover the difference

between what their generation assets would be worth under continued regulation and what they are

worth in a competitive market.” Tex. Pub. Util. Comm’n, Petition of Coalition of Ratepayers

for Rulemaking to Amend P.U.C. Substantive R. 25.263(i), Docket No. 28677, at 3 (Oct. 21, 2003)

(Joint Applicants’ reply to petition). Although the legislature decided to deregulate the industry into

a competitive market and to allow competitive forces to determine the value of the utilities’ services,

it was aware that the deregulation process might initially decrease the value of the utilities’

generation assets. Id. Stated differently, the legislature realized that concern about the viability of

the new, competitive market might dissuade investors from investing in the formerly regulated

utilities. Id. This potential investor concern might artificially lower the market value of the utility’s

assets below the value the assets would be appraised at in a more developed market. Id.

In light of this possibility, the legislature chose to “split the valuation process into two

parts” rather than estimate the market value of the utilities’ generation assets on the first day of

competition in 2002. Id. One part of the valuation process occurs in 2004 and utilizes one of the

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previously discussed valuation tools listed in subsections 39.262(h) and (i) to estimate the market

value of a utility’s generation assets. Id.

The second part of the valuation process occurs during the capacity-auction true-up

and concerns the two-year period after competition began. Id. Through the capacity auctions,

utilities were required to auction off entitlements to their generation capacity. Tex. Util. Code Ann.

§ 39.153(a). In other words, utilities were required to sell power entitlements in a wholesale market.

In addition to fostering competition, the legislature intended the capacity auctions to provide the

utilities with a way to recover some of their stranded costs for the 2002-2003 period. So long as a

utility is able to auction off entitlements for an amount that exceeds the utility’s operating costs, the

utility will be able to recover a portion of its stranded costs. See Tex. Pub. Util. Comm’n, Report

to the 75th Legislature, Volume 1, Electric Power Industry Scope of Competition and Potentially

Strandable Investment Report, at VI-3 to VI-4 (Jan. 1997). However, the same economic forces that

had the potential to artificially lower the value of a utility’s generation assets during the opening days

of competition also had the potential to artificially lower the price for the sale of power.

Accordingly, the legislature enacted the capacity-auction true-up to ensure that utilities receive the

full value of the entitlements that the utility would have received in 2002 and 2003 had regulation

continued.52 See Petition of Coalition of Ratepayers, Docket No. 28677, at 3 (explaining that

purpose of capacity-auction true-up is to make utilities whole for 2002 and 2003).

52
During the true-up, Jeffry Pollock, one of the Customers’ witnesses, testified that the
capacity-auction true-up ensures that utilities “receive their regulated cost of service for 2002 and
2003.” He further testified that the capacity-auction award was necessary because the final market
valuation did not occur until 2004.

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 To facilitate this recovery, the legislature authorized a comparison between the

regulated price of power previously estimated by the ECOM model and the actual revenue obtained

through the sale of power in the capacity auctions. Specifically, the legislature provided that a utility

is entitled to recover “any difference between the price of power obtained through the capacity

auctions . . . and the power cost projections that were employed . . . in the ECOM model to estimate

stranded costs.” Tex. Util. Code Ann. § 39.262(d)(2); see Tex. Pub. Util. Comm’n, Application of

Texas-New Mexico Power Company to Finalize Stranded Costs under PURA § 39.262, Docket

No. 29206, at 3 (March 3, 2004) (supplemental preliminary order). Under this provision, the

legislature effectively guaranteed that utilities would be able to recover the full amount predicted by

the ECOM model and would be entitled to an award to elevate their recovery to that level if they

were unable to auction their power entitlements for the predicted value.

As discussed previously, the ECOM model estimates the difference between a

utility’s “generation-related cost-of-service revenues” under regulation and the “market-based

revenues” under a competitive market or, alternatively, “the difference between a utility’s fixed costs

and the contributions to fixed costs of utility sales under competitive conditions.” Report to the

75th Legislature, at VI-2 to VI-3. A utility’s fixed costs consist of, among other things, depreciation

of its generation assets and a return on “existing generation-related investment capital.” Id. at VI-4.

By ensuring recovery up to the projected ECOM level, the legislature ensured “that

[] utilit[ies] ultimately receive[] the same fixed cost contribution from the capacity auction process

as the ECOM model predicted it would.” Petition of Coalition of Ratepayers, Docket No. 28677,

at 4; see also id. at 3 (describing how capacity-auction true-up considers “what contribution to fixed

costs” the utility’s generation assets “should generate in 2002-2003”); Application of Texas-New

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Mexico Power Company, Docket No. 29206, at 3 (“capacity-auction true-up ensures that a[] [utility]

with significant investment in generation assets will recover the power costs that the Commission

had projected, in the 2001 ECOM model, would be recovered for the 2002-2003 period”). In other

words, the capacity-auction true-up ensures that a utility will be made whole from the sale of

electricity in the competitive market during the time between when an initial estimate of the utility’s

net book value and stranded costs was made and the time of the final stranded-cost

determination in 2004.

The Commission clarified what a utility is entitled to recover through the capacity-

auction true-up when it promulgated its true-up rule. Rather than providing a strict comparison of

the value obtained in the capacity auctions with the ECOM value, the Commission’s rule requires

that two comparisons be made. First, a utility’s predicted revenue for the sale of power is compared

to its predicted fuel costs. Second, the utility’s actual revenue from the sale of power is compared

to its actual fuel costs. The true-up award is determined by calculating the difference between the

results obtained in the two comparisons. Specifically, the Commission’s rule provides that the

capacity-auction award will be calculated by using the following formula:

(ECOM [projected] market revenues - ECOM [projected] fuel costs) - (revenue from
capacity auctions - actual fuel costs)

See 16 Tex. Admin. Code § 25.263(i)(1).

By comparing the ECOM projected revenue with the projected fuel costs, the first part

of the equation produces a predicted “margin” that the utility is guaranteed that it will recover and

be able to use to contribute to its fixed costs, including depreciation. Petition of Coalition

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of Ratepayers, Docket No. 28677, at 4; see also CenterPoint, 143 S.W.3d at 97 (quoting from

documents filed by Joint Applicants that state that purpose of capacity-auction true-up is to ensure

that utilities obtain margin predicted by the ECOM model “to be available to contribute to fixed

costs and therefore to reduce stranded costs” and that contain examples of how amount obtained

through capacity auction should be used to reduce stranded costs). If a utility obtains less than the

predicted margin through its capacity auctions, the utility is entitled to recover a capacity-auction

true-up award to elevate its recovery to the predicted margin. Petition of Coalition of Ratepayers,

Docket No. 28677, at 4.

Although a utility is allowed to recover an award under certain circumstances, a utility

is not entitled to a capacity-auction award if the award is not needed to elevate the utility’s recovery

to the predicted margin. See CenterPoint Energy, 143 S.W.3d at 96 (explaining that capacity-auction

true-up award essentially guarantees “consumers and power companies that [] power compan[ies]

will receive no more and no less than [the] margin” calculated by ECOM model (emphasis added)).

Stated differently, if a utility obtains the predicted margin through its capacity auctions, the utility

will not be entitled to recover a capacity-auction award. Further, if a utility obtains more than the

predicted margin through its auctions, the utility will be required to refund that overrecovery to its

customers or, alternatively, apply that amount to reduce its stranded costs. Petition of Coalition of

Ratepayers, Docket No. 28677, at 4; see also Application of Texas-New Mexico Power Company,

Docket No. 29206, at 3 (explaining that capacity-auction true-up prevents utilities from

overrecovering through true-up by prohibiting utilities from retaining amount obtained in capacity

auctions that exceeds amount predicted by ECOM model).

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 Because the intended design of the capacity-auction true-up ensures that utilities will

be given no more and no less than a predicted margin to contribute to their fixed costs, we cannot

conclude that the Commission’s determination that the capacity-auction process and true-up allows

utilities to recover some of their stranded costs, particularly depreciation, is erroneous. Further, the

Joint Applicants’ reliance on Reliant I as standing for the proposition that the capacity-auction award

has nothing to do with stranded costs is misplaced. In reaching our decision in Reliant I, we did note

that the utilities code “seems to contemplate two parallel true-up tracks—one for stranded costs and

one for the several other true-up items” and that stranded costs and the other true-up costs “are

distinct concepts treated separately in the statute.” Reliant I, 101 S.W.3d at 140-41. However, we

made no determination regarding whether it was possible that a utility might recover some of its

stranded costs through one or more of the other non-stranded-cost true-ups, nor did we consider

whether it was proper to reduce a utility’s stranded-cost award to account for the fact that the utility

was actually able to recover a portion of its stranded costs through a manner that is distinct from the

stranded-cost true-up.53

The Commission has the Authority to Reduce the Joint Applicants’ Award

In their second set of arguments, the Joint Applicants assert that even if they were

53
As support for their argument that utilities do not recover portions of their stranded costs
through capacity auctions, the Joint Applicants point to a more recent order issued by the
Commission in which it stated that the definition of stranded costs does not include the capacity-
auction true-up and final-fuel balance. Tex. Pub. Util. Comm’n, Application of CenterPoint Energy
Houston Electric, LLC for a Financing Order, Docket No. 30485, at 6 (Dec. 20, 2004) (“Preliminary
Order”). However, the fact that the definitions are not synonymous does not preclude the possibility
that a portion of stranded costs might be recovered through the capacity-auction process.

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able to recover some of their stranded costs through the capacity-auction process, the Commission

did not have the authority to reduce their stranded-cost recovery. Specifically, they argue that neither

the utilities code nor the administrative code allow for this type of offset. As support for this

proposition, the Joint Applicants again rely on our Reliant I opinion, in which we concluded that if

the market value of a utility’s generation assets exceeded the net book value of the assets, the

Commission could not apply the surplus from the stranded-cost true-up to diminish the utility’s other

true-up recoveries. 101 S.W.3d at 141.

In a similar argument, the Joint Applicants contend that they were entitled to the full,

non-reduced stranded-cost award because the legislature specifically authorized them to recover both

a stranded-cost award and a capacity-auction award. In light of this allowance, the Joint Applicants

insist that recovering for both awards is not an overrecovery because recovery for both was the

legislature’s express desire.

As a preliminary matter, we note that the Joint Applicants are not contesting the

specific amount of the Commission’s reduction. In other words, the Joint Applicants are not

asserting that the Commission’s reduction is not supported by substantial evidence. Rather, they are

seeking a resolution to a pure question of law: whether the Commission has the authority to reduce

a utility’s stranded-cost award to account for the fact that the utility was able to recover a portion of

its stranded costs through the capacity-auction process. For the reasons that follow, we believe the

Commission’s interpretation of the various utilities code provisions as granting the Commission this

authority is correct and consistent with the language of the relevant statutes. See Coppock,

215 S.W.3d at 563 (noting that when statutes concern particularly complicated subject matters,

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agency’s construction of those statutes is given due consideration).

First, section 39.262(a) mandates that utilities “not be permitted to overrecover

stranded costs through the procedures established by this section or through the application of the

measures provided by the other sections of this chapter.” Tex. Util. Code Ann. § 39.262(a)

(emphasis added). Rather than limiting the determination of whether a utility overrecovers stranded

costs to the stranded-cost true-up alone, the code seems to require the Commission to assess whether

a utility is overrecovering its stranded costs in light of all the true-ups and procedures conducted as

part of the transition to competition.54 This idea is also supported by the directive that a “utility is

allowed to recover all of its net, verifiable, nonmitigable stranded costs.” Id. § 39.252(a) (emphasis

added). The use of the word “net” in section 39.252 is some indication that consideration of a

utility’s potential recovery of stranded costs from the other proceedings is mandated. Moreover,

allowing a reduction in light of an alternative source of recovery seems consistent with the very

concept of stranded costs: if the utility is able to recover for these costs, in whatever manner, then

the costs are no longer stranded or unrecoverable. Therefore, to the extent that the Joint Applicants

assert that they are entitled to a non-reduced stranded-cost recovery despite the fact that it would

amount to a double recovery, we disagree with that assertion.

Second, the supreme court previously opined that the Commission should diminish

a utility’s ultimate true-up recovery if the utility is able to recover a portion of its stranded costs

54
Much of the Joint Applicants’ arguments seem to rest on the premise that once a stranded-
cost calculation is performed, there can be no modification to that amount and that a utility is entitled
to that amount no matter the circumstances. However, these arguments ignore the legislative
mandate that utilities not be allowed to overrecover during the true-up proceedings. See
Tex. Util. Code Ann. § 39.262(a) (West 2007).

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through the capacity auction. Specifically, the supreme court stated that:

The amount of stranded cost recovery, if any, through capacity auction true-ups will
have to be considered . . . to ensure that there is no overrecovery of stranded costs.

...

[The opinion in Reliant I] does not foreclose the Commission from taking into
account any return of or on stranded costs that the margin from the capacity auction
true-up contains.

...

Preventing an overrecovery of stranded costs requires a determination, on a
company-by-company basis, of whether proceeds from a capacity auction true-up had
a component for return on or of stranded costs.

CenterPoint Energy, Inc., 143 S.W.3d at 84, 87.

Third, the Joint Applicants’ reliance on Reliant I as a bar to the Commission’s

reduction is misplaced. In Reliant I, we had to consider various challenges made to a rule

promulgated by the Commission. At the time the case was decided, the 2001 ECOM model

predicted that the utilities would have no stranded costs or “negative stranded costs.” Reliant I,

101 S.W.3d at 141. In other words, the utilities were predicted to need no stranded-cost recovery

because the market value of the assets exceeded their book value. One of the challenges to the rule

involved whether the Commission could apply the unexpected surplus to offset the utility’s recovery

under the other true-up proceedings. Id. at 138-39. Stated differently, the utility challenged the

propriety of employing the “negative” stranded costs to reduce the utility’s non-stranded-

cost recovery.

This Court ultimately decided that it would be improper to apply the unexpected

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surplus to diminish the recovery for the other costs that the legislature determined utilities were

entitled to recover as part of the transition to a competitive market. Id. at 141. In making this

decision, we noted that the utilities code does not require that a utility “refund a negative calculation

of stranded costs to ratepayers” and described how a negative stranded-cost calculation has no

significance and should not otherwise be considered except for the fact that it means a utility is not

entitled to a stranded-cost award. Id. Explained another way, a utility’s recovery for the other true-

ups should not be diminished simply because the market value of the utility’s assets unexpectedly

turned out to be greater than the book value of the assets.

We are not faced with the same situation here. In this case, it is undisputed that the

Joint Applicants have positive stranded costs. In other words, the Joint Applicants were entitled to

a stranded-cost award, and no one is arguing that the Joint Applicants’ recoveries under the other

true-ups should be diminished as a result of their recovery for stranded costs. On the contrary, we

are faced with deciding whether it is appropriate to reduce the Joint Applicants’ stranded-cost award

because they were able to recover some of their stranded costs through another proceeding.

The Commission’s Interpretation will Not Lead to Inequitable or Arbitrary Results

In their third set of arguments, the Joint Applicants pose a hypothetical that they insist

shows that the Commission’s interpretation of the various statutes would lead to inequitable results.

Essentially, through their hypothetical, the Joint Applicants attempt to show that the Commission’s

interpretation unfairly authorizes a reduction to a utility’s stranded-cost recovery if the utility is given

a capacity-auction award but prohibits a reduction to a utility’s recovery if the utility is not given a

capacity-auction award.

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 In their example, the Joint Applicants compare the capacity-auction true-ups for two

hypothetical utilities that sell the same number of entitlements. The first utility is unable to auction

its entitlements for the amount predicted by the ECOM model and therefore is entitled to a capacity-

auction award. The second utility auctions its entitlements for the exact amount predicted by the

ECOM model and is therefore not entitled to a capacity-auction award. Although the second utility

did not receive a capacity-auction award, the actual amount of money collected by each utility for

the sale of its entitlements is the same because the first company received the difference between the

predicted sale value and the amount actually obtained at auction through the capacity-auction award.

The Joint Applicants insist that under the Commission’s interpretation, the

Commission would be allowed to reduce the first utility’s stranded-cost recovery to account for any

alleged double recovery obtained in the capacity-auction-true-up, but it would be unable to make a

similar reduction to the second utility’s recovery because the second utility did not receive a

capacity-auction award. The Joint Applicants insist that an interpretation allowing for this type of

disparate treatment is not reasonable and cannot be upheld.

We fail to see why the Joint Applicants’ example proves that the Commission’s

interpretation of the statutes would necessarily lead to inequitable or arbitrary results. The example

given by the Joint Applicants distinguishes utilities that are able to recover their predicted price of

power through the capacity actions and those that must be reimbursed through a capacity-auction

award and, in light of this distinction, presupposes that reducing stranded-cost recovery is

appropriate only if a capacity-auction award is recovered. We find no support for

this presupposition.

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 We agree that it is possible that a utility could auction off entitlements to power for

an amount that meets or exceeds the amount predicted through the ECOM model. If the utility sells

entitlements to its generation capacity and obtains the exact margin predicted by the ECOM model,

the utility will not be entitled to receive a capacity-auction award. If the utility sells the entitlements

and obtains an amount that exceeds the predicted margin, the utility would not be entitled to a

capacity-auction award and would have to refund any amount that is in excess of the predicted value

to its customers or apply that amount to reduce its stranded costs. However, the fact that a utility is

not entitled to a capacity-auction award does not seem to be dispositive of whether the utility’s

stranded-cost recovery should be reduced.

In fact, under the Commission’s interpretation, it is immaterial whether a utility

actually recovers a capacity-auction award because the focus of the inquiry is whether the utility

recovered a portion of its stranded costs through the entirety of the capacity-auction true-up process.

In other words, the fact that a utility is not entitled to recover a capacity-auction award would not

seem to negate the possibility that the utility recovered a portion of its stranded costs through the

capacity-auction process.

On the contrary, given that the capacity-auction true-up ensures that a utility receive

no more and no less than a specific margin to contribute to its fixed costs, the utility will still recover

a portion of its stranded costs through the capacity auctions even though the utility is not entitled to

a capacity-auction award. Consequently, all the reasons previously discussed as supporting the

Commission’s reduction in this appeal would seem to have equal applicability to reducing the

stranded-cost award of a utility that is not entitled to a capacity-auction award. Accordingly, the

116
Commission’s interpretation does not arbitrarily or inequitably discriminate between utilities that

are entitled to a capacity-auction award and those that are not.

In light of all the reasons previously given, we conclude that the Commission’s

reduction to stranded costs was consistent with the governing statutes. Therefore, we conclude that

the district court properly affirmed that portion of the Commission’s order and, accordingly,

overrule the Joint Applicants’ final issue on appeal.

CONCLUSION

For the reasons previously given, we affirm in part and reverse in part the district

court’s judgment. Specifically, we conclude that the district court properly affirmed the

Commission’s use of an alternative valuation method for estimating the value of Genco’s generation

assets and its decisions to: limit to its alternative holding the deduction for the option given to

Reliant, reduce the Joint Applicants’ recovery to account for tax benefits given to them, allow the

Joint Applicants to recover the value of construction works in progress and plants held for future use,

allow the Joint Applicants to recover carrying costs on its capacity-auction award, and reduce the

Joint Applicants’ stranded-cost recovery to account for the partial recovery of stranded costs

obtained through the capacity-auction process. We also conclude that the district court properly

reversed the Commission’s decision to prohibit the Joint Applicants from recovering interest on

excess mitigation credits given to retail electric providers other than Reliant.

However, we further conclude that the district court improperly affirmed the

Commission’s decision to allow the Joint Applicants to recover the value of excess mitigation credits

that were given to Reliant and not passed on to their price-to-beat customers, improperly reversed

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the Commission’s decision to deny recovery for the interest on the excess mitigation credits given

to Reliant and not passed on to the Joint Applicants’ price-to-beat customers, and improperly

reversed the Commission’s use of an alternative method for determining the Joint Applicants’

capacity-auction award.

Accordingly, we remand this proceeding back to the district court for proceedings

consistent with this opinion. Furthermore, in light of the Joint Applicants and the Commission’s

agreement that we should remand to the Commission the issue of whether the Commission should

provide a remedy to account for the possibility that the Internal Revenue Service might later

conclude that certain deductions resulted in normalization violations, we remand this issue to the

district court with instructions that it remand the issue to the Commission for further proceedings.

David Puryear, Justice

Before Chief Justice Law, Justices Puryear and Henson

Affirmed in part; Reversed and Remanded in part on Motion for Rehearing

Filed: April 17, 2008

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