# Opinion

> Texas Court of Appeals, 3rd District (Austin) · December 20, 2007

URL: https://www.frixlaw.com/law-library/cases/2872319

## Case

- **Full name:** 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.
- **Court:** Texas Court of Appeals, 3rd District (Austin)
- **Decided:** December 20, 2007
- **Precedential status:** Published
- **Opinion:** Opinion
- **Cited by:** 0 later opinions in the Frix Law Library

## Citator (automated)

- No negative treatment found by the automated citator. That is not the same as a confirmation that the case is good law; read the citing cases.
- Full citator and citing cases: https://www.frixlaw.com/law-library/cases/2872319

## How later opinions describe it (automated extraction)

- holding that when order requiring payment was reversed, estate was entitled to recover money paid
- noting that when statutes concern particularly complicated subject matters, agency's construction of those statutes is given due consideration
- 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
- explaining that doctrine stands for proposition that expression of one thing means exclusion of all others
- 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"

## Opinion text

TEXAS COURT OF APPEALS, THIRD DISTRICT, AT AUSTIN
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
O P I N I O N
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
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
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).
After the deregulation process was completed, the power-generation and retail electric
markets would be subject to the "normal forces of competition" and "customer choices," but the
transmission-and-distribution utilities would remain regulated by the Commission. Id. § 39.001(a);
see Cities of Corpus Christi , 188 S.W.3d at 685 . However, the deregulation process is lengthy, and
the Commission retained partial regulatory powers over power generation and the sale of electricity
after January 2002. See, e.g. , Tex. Util. Code Ann. § 39.202 (allowing Commission some control
over prices charged by utilities). During the transition, affiliated retail electric providers were
required to charge a "price to beat" rate to their residential and small-business customers. (1) Id.
Prior to deregulation, utilities were allowed to recover from their customers the
prudent costs they incurred when acquiring power-generation assets. Reliant II , 153 S.W.3d at
183 n.5; Reliant I , 101 S.W.3d at 134 . The Commission allowed the utilities to recover these costs
over time by incorporating the costs into the rates that it approved. Reliant II , 153 S.W.3d at
183 n.5; Reliant I , 101 S.W.3d at 134 . As a result, utilities made significant investments in
generation-related assets with the expectation of eventually recovering their costs. See Cities of
Corpus Christi , 188 S.W.3d at 685 .
Recognizing that this type of reimbursement would not occur under deregulation,
utilities expressed their concern that under deregulation they would be unable to recover the costs
for their investments because competition would drive the rates too low. Reliant II , 153 S.W.3d at
183 n.5; Reliant I , 101 S.W.3d at 134 . (2) Because new utilities entering the market would not have
"embedded generation-related costs," they could set prices below the "level at which incumbent
utilities could recover their investments." Cities of Corpus Christi , 188 S.W.3d at 685 . (3) Therefore,
the incumbent utilities would either have to charge rates that were not competitive or absorb the
added expense. Id .
To prevent the possibility that utilities would have to absorb the costs, the legislature
provided a method by which a utility could recover its "stranded costs" or those costs representing
the "portion of the net book value of [the] utility's generation assets not yet recovered through
depreciation that has become unrecoverable in a deregulated market." Reliant I , 101 S.W.3d at 134 ;
see also Tex. Util. Code Ann. §§ 39.001 (b)(2) (finding that it is in public interest to "allow utilities
with uneconomic generation-related assets . . . to recover these reasonable excess costs over market
of those assets"), .251(3) (defining generation assets as "all assets associated with the production of
electricity, including generation plants"), .251(4) (defining market value as "the value the assets
would have if bought and sold in a bona fide third-party transaction or transactions on the open
market"), .251(7) (defining stranded costs as "the positive excess of the net book value of generation
assets over the market value of the assets"), (4) .252 (providing that utility is entitled to recover
stranded costs); 16 Tex. Admin. Code § 25.263 (g) (2007) (specifying what constitutes "net
book value").
Although the legislature allowed a utility to recover stranded costs, there were express
limitations imposed on this right. The utility was required to mitigate the amount of stranded costs
it incurs from purchasing electricity and "providing electric generation service," Tex. 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
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
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
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
lists several alternative methods by which an affiliated power-generation company could calculate
the market value of its generation assets for the purpose of calculating its stranded costs. Tex. Util.
Code Ann. § 39.262 (h)(1)-(4). These valuations utilize "stock prices and anticipated income streams
in a competitive market." Cities of Corpus Christi , 188 S.W.3d at 687 (citing Tex. Util. Code Ann.
§§ 39.201 (l), .262(h), (i)).
The true-up calculation obtained was the "final, controlling calculation of each
utility's stranded costs." Id. at 692 . The utility's actual stranded costs were determined by
subtracting the actual market value of the utility's generation assets from the book value of those
assets. Tex. Util. Code Ann. §§ 39.251 (7), .252(a), .262(c), (h), (i). If the number obtained in this
calculation was a positive number, then the utility was entitled to recover that amount in stranded
costs. (6) Reliant I , 101 S.W.3d at 136 .
The stranded-cost true-up was only one of several true-up calculations that had to be
performed as part of the transition to competition. See Tex. Util. Code Ann. § 39.262 (d)-(g). The
utilities code establishes "two parallel true-up tracks--one for stranded costs and one for the several
other true-up items." Reliant I , 101 S.W.3d at 141 . These non-stranded-cost calculations also can
"result in either credits or bills to the transmission and distribution utility from its affiliated
power generation company or retail electric provider." Id. at 136 (citing Tex. Util. Code Ann.
§ 39.262 (d)-(g)).
One of the non-stranded-cost true-ups relevant to this case involves the calculation
of a utility's "capacity-auction award." As part of the transition to a competitive market, utilities
were required to auction off entitlements to some of their generation assets. See Tex. Util. Code
Ann. § 39.153 (a). The capacity-auction award constituted the difference between the price that a
utility was predicted by the ECOM model to obtain for selling its power in the wholesale market
during the second step of deregulation and the price actually obtained at auction during the first years
of deregulation. See 16 Tex. Admin. Code § 25.263 (i), ( l ) (2007). After determining the capacity-auction award, the figure was netted with another true-up award called the final fuel balance. (7)
Tex. Util. Code Ann. § 39.262 (d).
Once the various calculations were made, they were all considered when determining
whether a utility was entitled to recover for costs. See 16 Tex. Admin. Code § 25.263 ( l )(1) (2007).
If the true-up balance was positive and greater than the projected costs, the utility was entitled to
recover the amount calculated. Based on the actual stranded costs calculated, the Commission was
authorized to alter the period of time during which a utility may collect the competition transition
charge or alter the amount of the charge. Tex. Util. Code Ann. §§ 39.201 ( l ), .262(c), (d)(1), (g);
16 Tex. Admin. Code § 25.263 ( l )(2)(A) (2007); Reliant I , 101 S.W.3d at 137 ; see also
Tex. Util. Code Ann. § 39.201 (b) (specifying nonbypassable delivery charges).
BACKGROUND
CenterPoint Energy Houston Electric, LLC ("CenterPoint"); Reliant Energy Retail
Services, LLC ("Reliant"); and Texas Genco, LP ("Genco") (cumulatively "Joint Applicants") (8) are
the unbundled components of the formerly integrated Reliant Energy: CenterPoint is the
transmission-and-distribution utility, Reliant is the affiliated retail electric provider, and Genco is
the power-generation company. In March 2004, they filed a joint application for a final true-up
proceeding to determine their recovery for stranded costs and non-stranded costs, including their
capacity-auction award. See Tex. Util. Code Ann. §§ 39.252 (a), .262(c), (d)(2).
In addition to the Joint Applicants, several other parties also intervened in the true-up
proceeding. The intervening parties were the Office of Public Utility Counsel ("Utility Counsel"),
see Tex. Util. Code Ann. § 13.003 (West 2007) (describing powers and duties of Utility Counsel),
and several coalitions of interested parties that either were within CenterPoint's service area or
purchased energy from 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
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
Balances Pursuant to PURA § 39.262 , Docket No. 29526, at 18 (Dec. 17, 2004) (Order on
Rehearing) ("order"). In its appraisal, the Commission concluded that the market value of the assets
was approximately $509 million higher than that estimated by the Joint Applicants. Consequently,
the Commission determined that the Joint Applicants' stranded costs were less than the amount
requested and reduced their recovery accordingly. After making the reductions previously discussed
and after utilizing its own market valuation, the Commission concluded that the Joint Applicants
were entitled to recover $1.222 billion in stranded costs and $121 million in interest under its
primary holding.
Under its alternative holding, the Commission assumed that the Joint Applicants
satisfied the necessary statutory requirements but made an additional reduction to the Joint
Applicants' recovery that it didn't make in its primary holding. The Commission deducted
approximately $508 million from the Joint Applicants' recovery to account for business practices
that the Commission believed were commercially unreasonable and for the tax benefit resulting from
this unreasonable behavior. After making all the relevant reductions, the Commission concluded
that the Joint Applicants were entitled to recover $945 million in stranded costs plus $68 million in
interest under its alternative holding.
The chart below details the relevant stranded-cost recovery requested by the Joint
Applicants and the various modifications made by the Commission in its primary and alternative
holdings:
Stranded Costs Calculations in Millions of Dollars (9)
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
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 $75 $101 $101
Additions
$150 $150 $150
Capacity Auction True-up
Cap. Auct. - Ded. + Add. $1,432 $966 $966
Interest $0 $168 $168
Capacity Auction Recovery
CA True-up + Interest $1,432 $1,134 $1,134
Joint Applicants' Appeal
After the order was issued, the Joint Applicants appealed the decision to the district
court. See Tex. Util. Code Ann. § 15.001 (West 2007) (stating that party to proceeding before
Commission is entitled to judicial review). The Customers and the Utility Counsel also appealed
the order, contending that the Commission erred in several respects.
After reviewing the Commission's order, the district court issued its judgment. The
district court affirmed the majority of the Commission's order, including the decision of the
Commission to perform its own assessment of the value of Joint Applicants' assets, but reversed
on two grounds. The district court's reversal increased the amount of stranded costs that the Joint
Applicants were entitled to receive. Specifically, the judgment concluded that the Commission erred
by (1) preventing the joint applicants from collecting $180 million in interest on the credits and
(2) disallowing $440 million from the capacity-auction true-up. Accordingly, the Joint Applicants'
recovery was increased by those amounts.
The Joint Applicants, the Customers, the Utility Counsel, and the Commission all
appeal the judgment of the district court. See id. §§ 15.001 (stating that any party to Commission
proceeding may appeal), 39.262(j) (specifying that final order by Commission is subject to judicial
review); Tex. Gov't Code Ann. § 2001.171 (West 2000) (explaining that after exhausting
administrative remedies, party aggrieved by final agency decision is entitled to judicial
review of decision).
STANDARD OF REVIEW
The proper standard of review to utilize in this case is complicated by the fact that
many of the issues are multifaceted, requiring the application of various standards in achieving a
final resolution. In light of this fact and for efficiency, we will attempt to summarize the various
standards that will be employed in this appeal.
Several of the issues raised in this appeal involve statutory construction, which is a
question of law that is reviewed de novo. See Bragg v. Edwards Aquifer Auth. , 71 S.W.3d 729, 734
(Tex. 2002); USA Waste Servs. of Houston, Inc. v. Strayhorn , 150 S.W.3d 491, 494
(Tex. App.--Austin 2004, pet. denied). In construing a statute, we must ascertain the legislature's
intent in enacting the statute. Fleming Foods of Tex. v. Rylander , 6 S.W.3d 278, 284 (Tex. 1999).
In making this determination, courts should look to the plain 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 ,
150 S.W.3d 491, 494 (Tex. App.--Austin 2004, pet. denied) (recognizing that legislature intends
to provide agencies with centralized expertise in regulatory areas with large degree of latitude in
accomplishing regulatory functions). However, courts do not defer to administrative interpretations
regarding questions that are not within the agency's expertise or that deal with nontechnical
questions of law. USA Waste Servs. , 150 S.W.3d at 494-95 .
Several issues also involve determinations regarding the Commission's authority.
As an agency, the Commission is a creation of the legislature and, therefore, "has no inherent
authority." Public Util. Comm'n v. City Pub. Serv. Bd. , 53 S.W.3d 310, 316 (Tex. 2001). For this
reason, the Commission possesses only those powers "expressly conferred upon it." Id. However,
when conferring a power upon an agency, the legislature also "impliedly intends that the agency have
whatever powers are reasonably necessary to fulfill its express functions or duties." Id. But an
agency may not "exercise what is effectively a new power, or a power contradictory to the statute,
on the theory that such a power is expedient for administrative purposes." Id.
Finally, several of the issues question whether many of the Commission's actions
were adequately supported by the evidence presented. We review these types of questions under a
substantial-evidence standard. Tex. Util. Code Ann. § 15.001 (West 2007) (stating that judicial
review of agency action is under substantial-evidence standard); Tex. Gov't Code Ann. § 2001.174
(West 2000) (allowing court to reverse agency determination if it is not supported by substantial
evidence). Under this standard, we are prohibited from substituting our judgment for the
Commission's "as to the weight of the evidence on questions committed to agency discretion."
Cities of Abilene, San Angelo, & Vernon v. Public Util. Comm'n , 146 S.W.3d 742, 748
(Tex. App.--Austin 2004, no pet.) (citing Tex. Gov't Code Ann. § 2001.174 ). In making this
determination, we are not asked to verify whether "the agency reached the correct conclusion, but
whether some reasonable basis exists in the record for the agency's action." Id. In fact, the evidence
may actually preponderate against the Commission's finding and be upheld as long as there is
enough evidence to suggest that the Commission's "determination was within the bounds of
reasonableness." Id.
DISCUSSION
The Commission's Primary Market Valuation
Market Valuation
Before addressing the various parties' arguments regarding the Commission's primary
market valuation, we will review the various methods by which a utility may calculate its stranded
costs. The utilities code lists four primary market-based valuation methods and one alternative
method for utilities to calculate the market value of generation assets--a necessary step for
calculating stranded costs. (10) The language of the statute places the burden of properly calculating
the market value of the assets on the utility. Section 39.262 of the utilities code mandates that "for
the purpose of finalizing the stranded costs estimate," "the affiliated power generation company
shall " calculate the market value of the generation assets by using one of four methods: (1) the sale-of-assets method; (2) the stock-valuation method; (3) the partial-stock-valuation method; or (4) the
exchange-of-assets method. Tex. Util. Code Ann. § 39.262 (h) (emphasis added); 16 Tex. Admin.
Code § 25.263 (f)(1) (2007); see also Tex. Gov't Code Ann. § 311.016 (West 2005) (explaining that
when construing statutes, courts should interpret "shall" as imposing duty).
The alternative method is found in subsection 39.262(i). This provision seems to
have been included to account for the possibility that a formerly regulated utility may not completely
unbundle by the time of the final true-up proceeding. 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
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
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
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).
Rather, they assert that the requirements that stock (1) be spun off and (2) sold on a national stock
exchange refer to two separate events. Stated differently, while the Joint Applicants acknowledge
that at least 19% of the stock had to be spun off, they do not believe that all of the spun-off stock
must subsequently be sold in a stock market. Rather, they assert that the "sold" requirement is
satisfied as long as some of the stock was traded in a stock exchange. Similarly, they contend that
the word "sold," when read in the context of the statute, merely means that the stock must be offered
for sale, not that it also be purchased, and refer to various definitions of the word "sell" to support
this assertion. See, e.g. , Webster's New Collegiate Dictionary 1051 (1st ed. 1973).
The Joint Applicants also insist that interpreting the partial-stock-valuation method
as requiring that all 19% of the distributed stock be sold in a stock exchange is tantamount to
demanding an "unworkable and impossible requirement that defeats the entire purpose of the
valuation statute." Essentially, they argue that although market value is determined through average
closing prices, many stock holders choose to retain ownership of their stock rather than sell it and
that this retention plays a key role in establishing the true market value of stock. In other words, they
argue that the rapid sale of stocks can lead to deflated stock prices but that stock retention helps to
create a higher stock price by providing a stabilizing effect and by demonstrating that the stock is
a desirable investment. Further, they assert that the benefit obtained through retention would cease
to exist if all of the spun-off stock has to be sold prior to the true-up. Moreover, they insist that
although not all 19% was sold, enough of the shares were sold and resold to establish an accurate
market value. Specifically, they note that although 15.2 million shares were originally distributed,
Genco stocks were traded 37.8 million times between January 2003 and March 2004. Finally, they
assert that a rigid requirement that a utility not only spin off 19% of its stock but that 19% also be
publicly traded would effectively require a utility to spin off more than 19% of stock in order to
guarantee that at least 19% is traded, which they urge would lead to significant tax penalties.
Specifically, they argue that CenterPoint and Genco would not have been able to file a joint tax
return if more of Genco's stock had been distributed. See 26 U.S.C.A. § 1504 (West 2002) (defining
"affiliated corporation" as one in which parent corporation owns 80% of corporation's stock).
When it interpreted the relevant statutory language, the Commission determined that
the phrase "sold . . . through a national stock exchange," as used in the statute, means that the stock
must actually be traded through a national stock exchange (i.e. offered for sale and purchased) and
not just offered for sale. (11) From this, the Commission reasoned that at least 19% of the stock must
be spun off and subsequently traded in a national stock exchange in order to satisfy the requirements
of the statute.
We believe that the Commission's interpretation is correct for several reasons. First,
the use of the word "and" without the insertion of a new subject in the phrase "spun off and sold"
indicates that both phrases apply to the language immediately preceding them: "at least 19 percent,
but less than 51 percent, of the common stock is." See Tex. Util. Code Ann. § 39.262 (h)(3).
Explained another way, the statute requires that (1) at least 19% of the stock be spun off and (2) at
least 19% of the stock be sold.
Second, there are other definitions of the word "sold" that do not mean simply to offer
for sale. For example, "sell" can also mean "to give up (property) to another for money or other
valuable consideration." Webster's New Collegiate Dictionary 1051 (1st ed. 1973). (12) Keeping in
mind that the word "sold" is the past tense of "sell," plugging this definition into the statute leads
to the conclusion that to satisfy the partial-stock-valuation requirements, at least 19% of the stock
must have been purchased by public investors prior to the true-up proceeding.
We believe that this construction of the statute more accurately reflects the legislative
intent than the Joint Applicants' interpretation. This construction comports with the use of the word
"sold" in other provisions of the utilities code. For example, under the sale-of-assets method for
determining market value, a utility may establish the market value of generation assets if the assets
have been "sold." Tex. Util. Code Ann. § 39.262 (h)(1). When the word "sold" is read in the context
of the remainder of the sentence, it becomes clear that "sold," as used in this subsection, does not
mean to offer for sale. The relevant portion of the provision provides as follows: "the total net value
realized from the sale establishes the market value of the generation assets sold ." Id.
(emphases added).
This interpretation is also consistent with the emphasis placed on establishing an
accurate market value apparent in the entire market-valuation subsection. Jones v. Fowler ,
969 S.W.2d 429, 432 (Tex. 1998) (providing that when construing statutes, courts should look to
entire act). Each market valuation method listed in subsection 39.262(h) requires that certain
minimum conditions be met before the utility may employ the method. Tex. Util. Code Ann.
§ 39.262 (h). For example, a utility may employ the sale-of-assets method only if its generation
assets are sold "in a bona fide third-party transaction under a competitive offering." Id.
§ 39.262(h)(1). Similarly, the exchange-of-assets method may be employed only if the generation
assets are transferred "in a bona fide third-party exchange transaction." Id. § 39.262(h)(4).
Moreover, under this method, the market value of the assets may be determined by offering the assets
for sale if the offer is made in a way guaranteeing "broad public notice of the offer and a reasonable
opportunity for other parties to bid on the asset." Id. These requirements are designed to ensure that
an accurate market value for the generation assets is calculated in order to comply with the
overriding mandate present throughout the statutory scheme: that a utility be allowed to recover but
not 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
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
with the statute by distributing the stock through an initial public offering. (14) See Walden v. Affiliated
Computer Servs. , 97 S.W.3d 303, 327 (Tex. App.--Houston [14th Dist.] 2003, pet. denied)
(explaining that initial public offering "is the commonly used term for the first offering of equity
securities of an issuer to the public pursuant to a registration statement"). Under this method, public
investors would purchase Genco stock from an underwriter shortly after the initial offering is made.
Because the sale would involve a transfer to public investors without first going through CenterPoint
shareholders, the Commission contends that the partial-stock-valuation requirements would be met
as long as more than 19% of the stock was purchased in the initial offer. (15) In other words, no more
than the desired amount of stock would need to be distributed because the stock is sold directly to
public investors.
Although the Joint Applicants acknowledge that an initial public offering would have
satisfied the necessary requirements, they insist that the market conditions during 2003 would not
have allowed a successful public offering. Essentially, they argue that an offering of 15.2 million
newly issued stocks would have deflated the value of the stock. (16)
Even if the value of the stock would have been temporarily lowered, the Joint
Applicants appear to concede that the value would have stabilized over time at a value similar to that
found by spinning off the stock first and then offering it for sale on a stock exchange. This undercuts
their assertion that it would have been 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
period of time and that stock that is sold on a stock exchange might be resold prior to the true-up
proceeding. In light of this, the legislature still required a utility to spin off and sell at least 19% of
the relevant stock to comply with the partial-stock valuation method. For this reason, we also
disagree with the Joint Applicants' assertion that the subsequent reselling of the Genco stock in the
stock market satisfied the legislative goal of establishing an accurate market value. (17)
For all the reasons previously given, the Commission's interpretation requiring that
a minimum proportion of a utility's total stock be sold in the stock market in order to accurately
determine market value is correct and consistent with the relevant statutory language. The Joint
Applicants failed to comply with this minimum requirement. Accordingly, the Commission
correctly determined that the partial-stock method could not be used to calculate the market value
of the generation assets.
The Commission Had the Authority to Consider Other Valuation Methods
The Utility Counsel and the Customers agree that the requirements of the partial-stock
method were not complied with but criticize the Commission's decision to estimate the market value
of the generation assets by a method not specifically listed in the utilities code. First, the Customers
assert that the Commission should not have allowed the Joint Applicants to recover any stranded
costs because they failed to meet their burden of establishing a viable market value. Essentially, the
Customers assert that the burden of proving stranded costs is on the utilities and insist that if a utility
fails to satisfy this burden, 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).
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.
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
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.
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,
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).
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.
Second, the cases that the Customers rely on in support of their argument that by
using an alternative valuation method, the Commission has impermissibly created a new power are
distinguishable. See Public Util. Comm'n v. GTE-Southwest, Inc. , 901 S.W.2d 401 (Tex. 1995);
Denton County Elec. Co-op v. Public Util. Comm'n , 818 S.W.2d 490 (Tex. App.--Texarkana 1991,
writ denied). In both cases, the utilities code specified that the Commission had the authority to
engage in an action only when certain conditions were met. GTE-Southwest, Inc. , 901 S.W.2d at
407 ; Denton , 818 S.W.2d at 492 . However, the parties argued about whether the Commission also
possessed the implied power to engage in the same activity when the conditions were not present.
GTE-Southwest, Inc. , 901 S.W.2d at 404 ; Denton , 818 S.W.2d at 492 .
In this case, the Commission is not asking this Court to conclude that, despite
statutory language authorizing the Commission to act only under certain circumstances, it has an
implied authority to act when the circumstances are not present. On the contrary, the Commission
is asking this Court to conclude that it has the authority to act to fulfill a legislative mandate when
the enumerated methods for compliance are not applicable to the present circumstances.
Specifically, the Commission asks this Court to conclude that when all the permissible methods of
calculating market value are unavailable because their conditions are not met, the Commission has
the implied authority to devise an alternative method for calculating market value in order to comply
with the legislative directive that utilities recover for stranded costs that they have incurred. Given
the strong legislative mandate, we must conclude that the Commission's authority to use an
alternative valuation method is "reasonably necessary to fulfill a function or perform a duty that the
Legislature has expressly placed in the" Commission's purview. See GTE-Southwest, Inc. ,
901 S.W.2d at 407 ; see also State v. Public Util. Comm'n , 883 S.W.2d 190, 194-97, 204 (Tex. 1994)
(concluding that Commission had implied authority to alleviate impact of regulatory lag by deferring
accounting, despite fact that this power was not explicitly listed in utilities code). Accordingly, we
must also conclude that the Commission's actions did not amount to an impermissible creation of
a new power.
The Method Chosen by the Commission was Proper
As part of its valuation, the Commission considered the control-premium panel's
report. In its report, the panel listed a range of possible values estimating the actual value of the
Genco's stock. The value ultimately chosen by the Commission was the mid-value of
the proposed range. (23)
Through several arguments, the Utility Counsel and the Customers assert that even
if the Commission was allowed to use an alternative valuation method, the Commission's utilization
of the report as a method for asset valuation was procedurally improper.
First, they contend that it was error to rely on the panel's report because it was
prepared solely for the purpose of determining whether a control premium existed and not for
determining the statutorily required estimate of Genco's market 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
utilities code, the Commission is required to adopt the panel's determination regarding whether a
control premium exists, see Tex. Util. Code Ann. § 39.262 (h)(3) (requiring Commission to "adopt"
control-premium amount determined by panel), they argue that there is no statutory authority for
allowing the panel to serve as a final fact-finder for the market valuation of generation assets.
Second, they argue that the Commission's utilization of the panel's report violated
their due process rights because they were not given prior notice and an opportunity to be heard
regarding the use of the control panel's report as a tool for market valuation. See Tex. Gov't Code
Ann. § 2001.051 (explaining that party is entitled to notice prior to hearing and opportunity to
present and respond to evidence); Madden v. Texas Bd. of Chiropractic Exam'rs , 663 S.W.2d 622,
626-27 (Tex. App.--Austin 1983, writ ref'd n.r.e.) ("To be meaningful, 'notice' and 'hearing'
require previous notice and a hearing relative to the issues of fact and law which will control the
result to be reached"). Further, they argue that they were unable to bring forth evidence refuting the
panel's findings related to the market value of Genco's stock. Moreover, they contend that because
the panel's report was used for ascertaining the market value of Genco's generation assets, they
should have been allowed to cross-examine the panel members. See Smith v. Houston Chem. Servs.,
Inc. , 872 S.W.2d 252, 278 (Tex. App.--Austin 1994, writ denied) (explaining that procedural rights
"encompassed by due process of law are generally recognized to be as follows: notice of hearing;
the opportunity to present argument and evidence and to rebut and test opposing evidence and
argument by cross-examination or other appropriate means; appearance with counsel; and a decision
by a neutral decision maker based on evidence introduced into the record of the hearing").
Finally, they allege that the Commission's utilization of the panel's report was
problematic because the panelists were not required to comply with contested-case requirements.
See, e.g., Tex. Gov't Code Ann. §§ 2001.051 -.178 (West 2000) (rules governing contested cases).
In particular, they assert that the panelists were allowed to communicate privately with third parties,
were allowed to obtain information from external sources when conducting 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
that determination was an estimation of the true market value of Genco's stock. See Tex. Util. Code
Ann. § 39.262 (h)(3) (explaining that control panel is composed of three financial experts "from the
top 10 nationally recognized investment banks with demonstrated experience in the United States
electric industry" and is assembled to determine whether value of publicly traded stock is "fairly
representative of the total common stock equity or whether a control premium exists for the retained
interest"). (25) In fact, in testimony given before the Commission, the panel's purpose was described
as determining a "fair market value for [Genco] in roughly the same time period as the valuation
time period in this case."
Furthermore, although the panel's report was not used in the precise manner originally
anticipated, the Customers and the Utility Counsel were on notice that the panel's report would be
used for the purpose of determining the true value of Genco's stock. See id. Moreover, the panel
provided all the relevant parties with notice of its actions and with the opportunity to be heard. First,
the parties were given notice that the panel had been convened and that it would be evaluating the
value of Genco's stock. Second, the parties were informed that the panel would have several open
hearings and were allowed to comment at the hearings regarding the panel's proposed methods for
making its determinations. Finally, the parties were allowed to file any concerns and information
that they had that were relevant to the panel's proposed analysis, including information related to
market value, and the panel pledged to consider the filings when making its decision.
Because the parties were aware that the panel's report would provide an estimate of
Genco's stock and that the evaluation would necessarily affect the Joint Applicants' stranded-cost
recovery, they had every incentive to participate in the panel's determination and to provide evidence
supporting their positions. (26) Moreover, the parties were informed prior to the Commission's
issuance of its final order that the partial-stock-valuation method could not be employed 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.
Although the Customers and the Utility Counsel complain that they were not allowed
to cross-examine the panel members, they cite to no authority for the proposition that cross-examining the panel members was appropriate and present no evidence that they filed a request to
cross-examine the panel. Furthermore, the Customers and the Utility Counsel were given the
opportunity to elicit testimony from and cross-examine witnesses that had information relevant to
the panel's determination, and the Commission questioned the panel members regarding their
valuation methods.
Additionally, given the panel's unique role in the true-up proceeding, it is not clear
that the requirements of a contested case have any applicability to the panel's determination.
Essentially, the panel's function is to determine whether a control premium exists and then to supply
the Commission with that information; its role is not to make decisions regarding the outcome of the
true-up proceeding. See Tex. Util. Code Ann. § 39.262 (h)(3); see also Tex. Gov't Code Ann.
§ 2001.060 (West 2000) (explaining that record consists of "data submitted to or considered by
hearing officer or members of agency"). Furthermore, even if the contested-case restrictions should
apply to the panel's determination, the prohibition against ex parte communications in contested
cases allows for ex parte communications when, as here, each party is given notice and allowed to
participate. Tex. Gov't Code Ann. § 2001.061 (a) (West 2000). Regardless, the Commission did
institute modified contested-case requirements to help ensure the panel's independence: the panel
(1) had to present all of the sources of information it relied on in making its determination, (2) had
to keep a log of all its meetings and communications, and (3) was prohibited from communicating
ex parte "with the Commissioners, the Policy Development Division staff assisting with the case
. . . , [and] any of the parties."
In light of the preceding, we must conclude that the Commission's use of the panel's
report was not procedurally improper. The Commission was faced with the dilemma of determining
the market value of Genco's stock when none of the methods listed in the utilities code could be
employed. In resolving this dilemma, the Commission logically used a statutorily 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
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
Commission determined that the option was not commercially reasonable because it imposed
significant restrictions on how Genco could operate but did not require Resources to pay for the
option. For this reason, the Commission concluded that by giving the option, CenterPoint failed to
fully mitigate its stranded costs as required by statute. See Tex. Util. Code Ann. § 39.252 (d)
(requiring Commission to consider utility's efforts to pursue commercially reasonable means to
reduce its stranded costs when determining amount of recovery); 16 Tex. Admin. Code
§ 25.263 (e)(4) (specifying that if Commission determines that utility failed to mitigate, it may reduce
net book value of generation assets).
The Commission determined that the commercial value of the option was
$330,314,000. In other words, the $330,314,000 represents the amount of money that Genco should
have received as compensation for the significant restrictions that it was encumbered with as a result
of the option, or alternatively, it represents the reduction to the overall value of Genco due to the
restrictions. After making this determination, the Commission reduced the amount of stranded costs
that the Joint Applicants were entitled to recover by that amount and by an additional $177,874,089
to account for the taxes that would have been paid had the option been purchased. The total amount
of the reduction was approximately $508 million. The district court affirmed the Commission's
determination to limit the application of the reduction to the alternative holding.
The Customers and the Utility Counsel agree that the reduction was appropriate but
argue that the reduction should have applied to the Commission's primary holding as well.
Essentially, they argue that regardless of what valuation method was employed, the option was
commercially unreasonable and that the Joint Applicants' recovery should, therefore, be reduced
irrespective of the valuation method chosen. They further contend that the Commission's decision
to limit the reduction to the alternative holding is arbitrary and capricious, unreasonable, and
contrary to the directive in subsection 39.252(d) that the Commission consider a utility's efforts to
reduce its stranded costs when determining the amount of money that the utility is entitled to recover.
See Tex. Gov't Code Ann. § 2001.174 (listing grounds for reversing agency's decision); Tex. Util.
Code Ann. § 39.252 (d).
We disagree. Subsection 39.252(d) is not a tool that is used to punish utilities for
commercially unreasonable conduct. Even if the provision allows the Commission to alter the
amount that a utility is entitled to recover if the utility fails to "pursue commercially reasonable ways
to reduce its potential stranded costs," Tex. Util. Code Ann. § 39.252 (d), there is no indication from
the words used in that section or in any provision of the utilities code that this power is
punitive in nature.
On the contrary, given the legislative directive compelling an accurate assessment of
stranded costs, it seems logical to assume that any power that the Commission may have to alter the
amount of recovery is limited to ensuring that the amount of stranded costs that a utility recovers
corresponds to the actual costs that the utility incurred as a result of deregulation and was not
intended to be used for punishing utilities for commercially unreasonable behavior. In other words,
if the commercially unreasonable behavior benefits the utility financially and lessens the impact of
the stranded costs, then the amount that the utility is entitled to recover should be modified.
However, if the commercially unreasonable behavior has no financial impact or if the financial
impact is either irrelevant to or accounted for in the valuation method chosen, then adjusting the
amount of recovery would be contrary to the legislative directive.
In its primary holding, the Commission considered several factors when determining
the market value of Genco's stock. First, although the Commission correctly concluded the sale-of-assets method could not be used to estimate Genco's market value, the Commission did consider the
amount offered to purchase Genco when attempting to ascertain the market value of Genco's assets.
The offer came several months after the option expired and after the restrictions placed upon Genco
by the option had ended. As a result, any detrimental effect on Genco's value resulting from the
option should have dissipated. Therefore, the offer's usefulness as an estimate of Genco's market
value was arguably unaffected by the option.
However, even if the potentially negative effects of the option had not fully
dissipated, the Commission did not rely solely on the proposed sale price when determining Genco's
market value. While performing its estimate, the Commission also considered the valuation report
prepared by the control-premium panel. To establish Genco's true value, the panel performed
several analyses utilizing the following factors: the market value of other publicly traded companies,
the price of electricity, historical trends, forecasted market conditions, and the amount obtained by
the prior sale of generation assets. None of these analyses were affected by the option. Further, the
actual value ultimately chosen by the Commission was the midpoint of the values calculated by the
valuation panel.
After concluding that the various market valuations that it relied on in its primary
holding were unaffected by the option, the Commission determined that it "did not need to examine
the [Joint Applicants'] business practices" regarding the option and that no adjustment for
commercially unreasonably behavior needed to be made. In light of the preceding, the
Commission's decision to limit the adjustment to its alternative holding was reasonable and did not
violate subsection 39.252(d).
For all the reasons previously given, we conclude that the district court properly
affirmed the Commission's use of an alternative valuation method and its decision to limit the
deduction for the option to its alternative holding.
Alternate Holding
Having concluded that the Commission possessed the authority to perform the market
valuation it made under its primary holding, we need not address the parties' arguments regarding
the propriety of the Commission's alternative holding, the propriety of the reduction to stranded-cost
recovery due to the option given to Resources, or whether the reduction should have been "grossed-up" to account for federal taxes.
Excess Mitigation Credits
The Customers and the Utility Counsel also challenge the Commission's decision to
allow the Joint Applicants to recover, as stranded costs, $470 million for credits that CenterPoint had
been ordered to give to Reliant. 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).
In addition, to help smooth the transition to a competitive market, the Commission
prepared a report--the 1998 ECOM Report--estimating the potential stranded costs that nine
utilities would have at the start of retail competition in 2002. Cities of Corpus Christi , 188 S.W.3d
at 686 . If the 1998 ECOM Report projected that a utility would have stranded costs, the utility was
required to engage in steps to mitigate its predicted stranded costs. Tex. Util. Code Ann. § 39.254 ;
CenterPoint Energy, Inc. , 143 S.W.3d at 88 . To facilitate mitigation, the utilities code provided "a
number of tools to an electric utility to mitigate stranded costs." Tex. Util. Code Ann. § 39.254 .
These tools allowed a utility "to reduce . . . its stranded costs each year" by reducing the net book
value of generation assets. Id.
During the interim period, utilities were required to file annual reports with the
Commission detailing any earnings they had that were in excess of their costs. See id. § 39.257
(requiring utility to file report identifying "any positive difference between annual revenues . . . and
annual costs"). These reports were used to determine whether the utilities were obtaining excess
earnings as a result of the frozen utility rates. CenterPoint Energy, Inc. , 143 S.W.3d at 88 . If a
utility's annual report indicated that the utility had positive earnings for the year, then the utility was
compelled to apply the amount of the excess earnings to reduce "the net book value" of the
potentially stranded assets. Tex. Util. Code Ann. § 39.254 .
After competition began, the Commission was required to perform another ECOM
analysis for the utilities sometime before the true-up proceedings in 2004. See id. § 39.201(h). This
analysis used updated company-specific information to estimate each utility's predicted stranded
costs. Id. If, after performing the calculation, the Commission predicted that a utility would have
stranded costs, then the Commission was authorized to facilitate recovery for the stranded costs.
Cities of Corpus Christi , 188 S.W.3d at 686-87 ; see Tex. Util. Code Ann. § 39.201 (b)(3).
When the Commission performed the second ECOM analysis, it predicted that the
Joint Applicants would not have any stranded costs. Essentially, the calculation predicted that the
expected market value of the generation assets would exceed the net book value of the assets. As
a result, the Commission concluded that mitigation efforts engaged in by 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.
Furthermore, the Commission concluded that the retail electric providers could not
pass through the value of the credits to their price-to-beat customers because passing through the
benefit of the credits would violate the provision of the utilities code prohibiting retail electric
providers from charging rates that were different than the price to beat. See Tex. Util. Code Ann.
§ 39.202 (e) (providing that retail electric providers can not charge different rates until one or more
events occur).
During the 2004 true-up proceeding, it was discovered that the second ECOM
estimate was inaccurate and that the Joint Applicants had actually incurred significant stranded costs.
As a result, the Commission ordered the utilities to cease crediting to the retail electric providers the
value of the excess mitigation and the corresponding interest on the retained earnings. Because the
Commission discontinued the credits prior to the seven-year deadline, not all of the excess earnings
had been credited to retail electric providers.
In its order, the Commission concluded that the amount of excess earnings that had
not been credited to retail electric providers should be used to mitigate the Joint Applicants' stranded
costs. As for the credits already given, the Commission concluded that the Joint Applicants could
recover the value of the principal amount of the credits given to retail electric providers, including
the co-applicant Reliant, regardless of whether the value of the credit had ultimately been passed
through to Reliant's customers. In other words, even though the Commission had previously
prohibited Reliant from passing the benefit of the credits on to its price-to-beat customers, the
Commission determined that the Joint Applicants should recover the value of the credits that were
not passed through to price-to-beat customers as well as the value passed through to non-price-to-beat customers.
Although the Commission allowed the Joint Applicants to recover the principal
amount of the credits, it denied recovery for the interest portion of the credits that the Commission
had ordered CenterPoint to award in order to account for the value of the excess earnings that had
not yet been credited to retail electric providers. However, the Commission did authorize a different
kind of interest recovery. The Commission allowed the Joint Applicants to recover 11.075% in
interest on the principal component of the excess mitigation credits actually credited to the retail
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.
More specifically, the dispute on appeal concerns whether the Joint Applicants should be allowed
to recover for the portion of the credits given to Reliant that the Commission prohibited Reliant from
passing through to its price-to-beat customers.
The Commission and the Joint Applicants argue that the Commission's decision to
allow the Joint Applicants to recover for the excess mitigation credits given to Reliant was proper.
First, they assert that the issuance of the credits led to an increase in stranded costs
and that denying recovery for these costs would result in an under-recovery of stranded costs in
violation of the utilities code. See Tex. Util. Code Ann. § 39.252 (a) (specifying that utility is entitled
to recover "all of its net, verifiable, nonmitigable stranded costs"). As support for this assertion, they
note that due to the inaccurate ECOM calculation, the Commission ordered CenterPoint to credit the
value of the excess earnings to Reliant rather than allowing CenterPoint to use the excess earnings
to reduce the net book value of generation assets. Because of this, the Joint Applicants and the
Commission argue that the amount of stranded costs increased and that the Joint Applicants should
be able to recover for those costs.
Second, they contend that recovery should not be denied even though Reliant was
CenterPoint's co-applicant for stranded-cost recovery. Essentially, they argue that any benefit
bestowed upon Reliant should not prevent CenterPoint from recovering because CenterPoint and
Reliant are distinct corporate entities. In other words, the benefit given to Reliant did not benefit
CenterPoint; to the contrary, the Joint Applicants and the Commission assert that the benefit given
to Reliant was to the detriment of CenterPoint.
Third, the Joint Applicants and the Commission contend that recovery should not be
denied even though Reliant did not pass the benefit of the credit on to its price-to-beat customers. (29)
In essence, they argue that by retaining the value of the credits, Reliant was only doing what it was
ordered to do by the Commission and that the Joint Applicants should not be punished for complying
with the Commission's orders. (30)
Alternatively, the Joint Applicants insist that if CenterPoint is unable to recover the
value of the credits it gave to Reliant during the true-up reconciliation, it will be unable to recover
for this imposed cost in any other manner. In essence, the Joint Applicants argue that there is no
statutory provision that allows a utility to transfer the value of credits that it was awarded to one of
its affiliates under the circumstances present in this case and therefore insist that there is no way for
CenterPoint to reclaim the value of the credits from Reliant. In support of this argument, they argue
that the only provision of the utilities code authorizing the transfer of credits between affiliated
utilities is inapplicable to this circumstance. See id. § 39.262(e) (requiring retail electric provider
to credit its affiliated transmission-and-distribution utility "any positive difference" between price
to beat and actual market price). Moreover, the Joint Applicants insist that Reliant has already
credited the maximum amount possible under this provision and, therefore, satisfied its statutory
obligation. See id.
We disagree with the assertions of the Commission and the Joint Applicants.
Assuming without deciding that Reliant and CenterPoint are completely separate entities, the utilities
code treats formerly bundled utilities as related entities for the purpose of stranded-cost
reconciliation. For example, the utilities code requires formerly bundled utilities to apply together
for the recovery of stranded costs. See id. § 39.262(c). This joint treatment is most pronounced in
subsection 39.262(a), which provides, in relevant part, as follows:
An electric utility, together with its affiliated retail electric provider and its 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
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)
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
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
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
Commission abused its discretion by making the deductions because the deductions violated certain
requirements of the Internal Revenue Service. Second, they argue that even if the reductions were
proper, this Court should still find that the Commission abused its discretion by failing to provide
a remedy for the Joint Applicants in the event that the Internal Revenue Service later concludes that
there was a tax violation.
For reasons unrelated to deregulation, Congress had previously given various
companies, including the Joint Applicants, two types of tax benefits: tax credits and deferred
taxation. (34) The relevant tax credits are called investment tax credits. See generally 68 Fed.
Reg. 10190 (March 4, 2003) (describing effects of deregulation on investment tax credits). From
1962 to 1986, Congress gave these credits to various utilities to encourage them to invest in new
equipment, including generation assets. Unlike a deduction that offsets taxable income, the
investment tax credit offsets a utility's tax liability. Under regulation, although the utility
experienced the benefit of the credits early on, it was required to pass the benefit on to its customers
over the book life of the asset--a process referred to as normalization.
The deferred taxes relevant in this issue are called excess deferred income taxes.
Deferred taxation resulted from Congress's decision to allow utilities to accelerate the depreciation
of various assets and, as a result, pay significantly reduced income taxes. See Public Util. Comm'n
v. GTE-Southwest, Inc. , 833 S.W.2d 153, 166 (Tex. App.--Austin 1992), rev'd on other grounds ,
901 S.W.2d 401 (Tex. 1995).
Although the taxable value of the assets was quickly depreciated, the regulatory value
of the assets depreciated using a straight-line method. Id. Explained another way, for rate-making
purposes, the value of the assets was reduced by the same amount each year. The amount of taxes
charged to the customers was based on the regulatory value. As a result, the amount of taxes paid
by the customers during the first portion of an asset's expected life was more than the amount of
income taxes actually paid by the utility. City of Somerville v. Public Util. Comm'n , 865 S.W.2d
557, 564 (Tex. App.--Austin 1993), overruled by Public Util. Comm'n v. GTE-Southwest ,
901 S.W.2d 401 (Tex. 1995). The resulting difference between the tax assessed and the amount
collected from customers for taxes was deposited into an account. GTE-Southwest, Inc. , 833 S.W.2d
at 166 . During the later parts of an asset's expected life, the amount of taxes paid by the utility was
more than the amount collected from the customers. City of Somerville , 865 S.W.2d at 564 . During
this period, the balance of the taxes owed that were in excess of those collected from customers were
paid out of the account previously mentioned.
The excess deferred income taxes at issue in this case resulted from the reduction of
the corporate income-tax rate. See generally 68 Fed. Reg. 10190 (describing effects of deregulation
on deferred income taxes). Before the reduction, the utilities were collecting deferred taxes at a
higher tax rate. However, because the tax rate was lowered, the utility would never have to pay the
full amount of the deferred taxes collected. The balance of the deferred taxes accrued at the higher
rate over the amount accrued at the lower rate constituted the excess deferred income taxes. Utilities
passed through the benefits of the excess deferred taxes by utilizing a normalization method.
The Deductions
On appeal, the Joint Applicants dispute the propriety of the Commission's decision
to reduce the amount of stranded costs by the present-day values of the investment tax credits given
to them and the excess accumulated deferred income taxes that they accumulated. The Joint
Applicants do not dispute that retaining the credits and deferred taxes benefitted them or that their
customers were entitled to receive these benefits. However, they do insist that utilities were
prohibited from passing the benefits on to customers earlier than allowed by the Internal Revenue
Service. In other words, the Joint Applicants contend that utilities were required to pass through the
benefits to their customers over the full depreciation schedule of their assets and were not allowed
to return the value of the benefits at an earlier time. Furthermore, they argue that passing through
the benefits earlier than allowed--an alleged normalization violation--would have exposed a utility
to potentially significant penalties. See Tax Reform Act of 1986, Pub. L. No. 99-514, 100 Stat. 2146
(stating that normalization method is not satisfied if excess tax reserve is reduced more quickly than
allowed); see also 26 C.F.R. 1.167( l )-1 (stating that assets may be depreciated by straight-line
depreciation or by normalization method). Specifically, they assert that a utility that commits a
normalization violation could be required to pay back the remaining balance of the credits and be
denied the benefit of claiming accelerated depreciation of their assets.
Based on the preceding, the Joint Applicants argue that by offsetting the stranded-cost
recovery for the credits and deferred taxes, the Commission has 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
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.
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)
In light of the prohibition against

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Source: Frix Law Library, https://www.frixlaw.com/law-library/cases/2872319. Public record. Not legal advice.