# Opinion

> Texas Court of Appeals, 3rd District (Austin) · December 16, 2004

URL: https://www.frixlaw.com/law-library/cases/2867551

## Case

- **Full name:** Reliant Energy, Incorporated Office of Public Utility Counsel And Gulf Coast Coalition of Cities/Magic Valley Electric Cooperative, Inc. Medina Electric Cooperative, Inc. Rayburn Country Electric Cooperative, Inc. And City of Bryan v. Public Utility Commission of Texas Consumer Owned Power Systems City of Houston Texas Industrial Energy Consumers State of Texas And Constellation NewEnergy, Inc./Public Utility Commission of Texas And Reliant Energy, Incorporated
- **Court:** Texas Court of Appeals, 3rd District (Austin)
- **Decided:** December 16, 2004
- **Precedential status:** Published
- **Opinion:** Opinion
- **Cited by:** 0 later opinions in the Frix Law Library

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## Opinion text

TEXAS COURT OF APPEALS, THIRD DISTRICT, AT AUSTIN

444444444444444444444444444
ON MOTION FOR REHEARING
444444444444444444444444444

NO. 03-02-00246-CV

Reliant Energy, Incorporated; Office of Public Utility Counsel; and Gulf Coast Coalition of
Cities/Magic Valley Electric Cooperative, Inc.; Medina Electric Cooperative, Inc.; Rayburn
Country Electric Cooperative, Inc.; and City of Bryan, Appellants

v.

Public Utility Commission of Texas; Consumer Owned Power Systems; City of Houston;
Texas Industrial Energy Consumers; State of Texas; and Constellation NewEnergy,
Inc./Public Utility Commission of Texas; and Reliant Energy, Incorporated, Appellees

FROM THE DISTRICT COURT OF TRAVIS COUNTY, 261ST JUDICIAL DISTRICT
NO. GN104128, HONORABLE F. SCOTT McCOWN, JUDGE PRESIDING

OPINION

Our opinion and judgment issued on August 26, 2004 are withdrawn and the

following opinion is substituted.

Several parties appeal from the district court’s judgment affirming a final order of the

Public Utility Commission (“the Commission”) setting cost-of-service rates for the transmission and
distribution utility (“TDU”) of Reliant Energy, Inc. (“Reliant”).1 After a contested case proceeding,

the Commission entered an order setting rates below the level Reliant sought for its TDU. Reliant

and several parties who intervened at the agency level sought review by the district court. The

district court concluded that one of the Commission’s findings of fact was a prohibited advisory

opinion, but otherwise affirmed the Commission’s order. Reliant, Gulf Coast Coalition of Cities

(“Gulf Coast”), Office of Public Utility Counsel (“OPC”), and Consumer Owned Power Systems2

(“COPS”) all challenge the district court’s affirmance of the Commission’s order. We will reverse

the portion of the district court’s judgment affirming the Commission’s inclusion of $107.3 million

for the interconnection of Merchant Plant 4. We affirm the district court’s judgment in all other

respects. We remand the case to the Commission for further proceedings.

BACKGROUND

The general outline of Texas’s scheme for the transition from a regulated electric

utility industry to a competitive marketplace has been addressed in detail. See, e.g., Reliant Energy,

Inc. v. Public Util. Comm’n, 101 S.W.3d 129, 133-36 (Tex. App.—Austin 2003), rev’d in part sub

nom. CenterPoint Energy, Inc. v. Public Util. Comm’n, 47 Tex. S. Ct. J. 672, 2004 Tex. LEXIS 540

(Tex. June 18, 2004); Reliant Energy, Inc. v. Public Util. Comm’n, 62 S.W.3d 833, 835-36 (Tex.

App.—Austin 2001, no pet.). Under the regulated system, a single utility generated electricity, built

1
During proceedings before the Commission, Reliant Energy Houston Lighting and Power
changed its name to Reliant. Although some documents filed with the Commission refer to the
company as “Houston Lighting and Power” or “HLP,” we will refer to the company as “Reliant.”
2
Appellants Magic Valley Electric Cooperative, Inc., Medina Electric Cooperative, Inc.,
Rayburn Country Electric Cooperative, Inc., and the City of Bryan are collectively referred to as
“Consumer Owned Power Systems.”

2
and maintained the electricity distribution grid, and sold the electricity to consumers. In 1999, the

legislature added chapter 39 to the Public Utility Regulatory Act (“PURA”),3 finding that the “public

interest in competitive electric markets requires that, except for transmission and distribution

services and for the recovery of stranded costs, electric services and their prices should be

determined by customer choices and the normal forces of competition.” PURA § 39.001(a).

PURA chapter 39 requires existing integrated utilities to separate, or unbundle, into

three units by January 1, 2002: a power generation company, a TDU, and a retail electric provider.

Id. § 39.051(b). Despite the emphasis on competition in the retail market, the Commission will

continue to regulate the TDUs’ rates and services. As part of the transition, the statute required

Reliant and other electric utilities to file an unbundled cost-of-service rate case to establish

transmission and distribution rates for their TDUs, and the Commission to set transmission and

distribution rates as of January 1, 2002. Id. § 39.201.

Cost-of-service rates are set to allow a utility to recover a return on its invested

capital, also called rate base, plus its reasonable and necessary expenses.4 Because many of the

3
Tex. Util. Code Ann. §§ 11.001-64.158 (West 1998 & Supp. 2004) (hereinafter “PURA”).
4
This Court has discussed the components of the “rate base”:

The term “invested capital” is not made the subject of a specific definition in
PURA although the term is said to be synonymous with the term “rate base,” see
16 Tex. Admin. Code § 25.231(c)(2) (2003); and, the “components” of invested
capital are described broadly as “property used by and useful to the utility in
providing service,” appraised based on original cost less depreciation. PURA
§ 36.053(a). In fixing an electric utility’s rates, the Commission exercised a
statutory authority to separate and allocate “costs of facilities, revenues,
expenses, taxes, and reserves” in arriving at rates that were just and reasonable.
Id. § 36.055.

3
unbundled TDUs did not exist for a full year before January 1, 2002, the legislature required the rates

for the new transmission and distribution service to be based on a forecasted 2002 test year. See id.

§ 39.201(b)(1); see also id. § 11.003(20).

PURA provides general guidelines for setting rates. The Commission is required to

“establish the utility’s overall revenues at an amount that will permit the utility a reasonable

opportunity to earn a reasonable return on the utility’s invested capital used and useful in providing

service to the public in excess of the utility’s reasonable and necessary operating expenses.” Id.

§ 36.051. A utility is entitled to rates sufficient to repay its expenses, without a return or profit on

those expenses, and to provide a return on the invested capital included in its rate base, without

repaying that investment. Cities for Fair Util. Rates v. Public Util. Comm’n, 924 S.W.2d 933, 935

(Tex. 1996). In determining the amount of invested capital used to serve customers, the Commission

uses the “original cost, less depreciation, of property used by and useful to the utility in providing

service.” PURA § 36.053(a). To establish the utility’s reasonable and necessary operating expenses,

the Commission starts with the expenses incurred during the test year, and then adjusts those

expenses for known and measurable changes. 16 Tex. Admin. Code § 25.231(b) (2004). Operating

expenses include such things as depreciation, federal income taxes, and employee wages. See id.

Intending to streamline the rate proceedings for the individual TDUs, the Commission

initiated a generic proceeding (Docket No. 22344) to determine issues common to all the affected

TDUs, then apply the generic determination in the utility-specific cases. The Commission’s final

American Elec. Power Co. v. Public Util. Comm’n, 123 S.W.3d 33, 35 (Tex. App.—Austin 2003,
no pet.).

4
order in the Reliant-specific case included both recovery of estimated stranded costs5 for Reliant’s

generation company and cost-of-service rates for the Reliant TDU. See generally Tex. Pub. Util.

Comm’n, Application of Reliant Energy for Approval of Unbundled Cost of Service Rate Pursuant

to PURA § 39.201 and Public Utility Commission Substantive Rule § 25.344, Docket No. 22355

(Oct. 3, 2001) (hereinafter, “Reliant Order”).

The parties challenged the Commission’s order on several grounds in the district

court. The court decided that the issue of interest on excess mitigation credits was not ripe for

decision and thus that the finding of fact (and the related discussion) on that issue was a prohibited

advisory opinion, but otherwise affirmed the Commission’s order.

DISCUSSION

In this appeal, the parties challenge the Commission’s decisions regarding elements

of the rate base, rate of return, expenses, and rate design. Our review of this appeal is under the

5
Stranded costs are “the positive excess of the net book value of generation assets over the
market value of those assets . . . .” PURA § 39.251(7). Under regulation, a utility could recover
over time its prudently incurred costs of acquiring power-generation assets through rates approved
by the Commission and paid by captive customers. See Reliant Energy, Inc. v. Public Util. Comm’n,
101 S.W.3d 129, 134 (Tex. App.—Austin 2003), rev’d in part sub nom. CenterPoint Energy, Inc.
v. Public Util. Comm’n, 47 Tex. S. Ct. J. 672, 2004 Tex. LEXIS 540 (Tex. June 18, 2004). The
Commission facilitated this cost recovery by incorporating depreciation expenses into approved
rates. See Central Power & Light Co. v. Public Util. Comm’n, 36 S.W.3d 547, 553 (Tex.
App.—Austin 2000, pet. denied) (“CPL”). In a deregulated environment, however, competition
could drive rates to levels so low that a formerly regulated utility would be unable to recoup its
investments. Stranded costs represent that portion of the net book value of a utility’s generation
assets not yet recovered through depreciation that has become unrecoverable in a deregulated
environment. See City of Corpus Christi v. Public Util. Comm’n, 51 S.W.3d 231, 237-38 (Tex.
2001); see also PURA § 39.251(7).

5
substantial-evidence standard. PURA § 15.001. That standard is largely deferential to the

Commission’s decision, as set out in the following statute:

If the law authorizes review of a decision in a contested case under the substantial
evidence rule or if the law does not define the scope of judicial review, a court may
not substitute its judgment for the judgment of the state agency on the weight of the
evidence on questions committed to agency discretion but:

(1) may affirm the agency decision in whole or in part; and

(2) shall reverse or remand the case for further proceedings if substantial
rights of the appellant have been prejudiced because the administrative
findings, inferences, conclusions, or decisions are:

(A) in violation of a constitutional or statutory provision;

(B) in excess of the agency’s statutory authority;

(C) made through unlawful procedure;

(D) affected by other error of law;

(E) not reasonably supported by substantial evidence considering the
reliable and probative evidence in the record as a whole; or

(F) arbitrary or capricious or characterized by abuse of discretion or
clearly unwarranted exercise of discretion.

Tex. Gov’t Code Ann. § 2001.174 (West 2000).

We presume that the Commission’s findings are supported by substantial evidence,

and the contestant bears the burden of proving otherwise. See Southwestern Pub. Serv. v. Pub. Util.

Comm’n, 962 S.W.2d 207, 215 (Tex. App.—Austin 1998, pet. denied). A court reviewing an agency

action shall reverse and remand the cause to the agency when substantial rights of the appellant have

been prejudiced by an agency’s findings that are not reasonably supported by substantial evidence

6
considering the reliable evidence in the record as a whole. Tex. Gov’t Code Ann. § 2001.174(2)(E).

We may not substitute our judgment for that of the agency on the weight of the evidence.

Southwestern, 962 S.W.2d at 215. “Substantial evidence” does not mean a large or considerable

amount of evidence, but rather such relevant evidence as a reasonable mind might accept as adequate

to support a conclusion of fact. Pierce v. Underwood, 487 U.S. 552, 564-65 (1988); Lauderdale v.

Department of Agric., 923 S.W.2d 834, 836 (Tex. App.—Austin 1996, no writ). We must uphold

an agency’s finding even if the evidence actually preponderates against the agency’s finding so long

as enough evidence suggests the agency’s determination was within the bounds of reasonableness.

Southwestern, 962 S.W.2d at 215.

The parties raise several complaints. Gulf Coast, COPS, and OPC argue that the

amounts used to calculate invested capital should have included an average of the investment for

transmission lines in 2002 rather than the total amount that the Reliant TDU will have invested in

transmission facilities by the end of 2002. Gulf Coast also disputes amounts included for

transmission lines to serve one particular generator. Gulf Coast further contends that the

Commission should have returned the value of nuclear insurance premiums to customers. Gulf

Coast and OPC complain that the return on equity used to determine the rate of return was

determined in the generic proceeding. OPC complains about the transmission cost recovery factor

and the amount the Commission included in rates for a minimum delivery cost necessary for each

customer, regardless of amount of use. OPC also challenges the cost escalation and asset

degradation factors the Commission assessed on various items on Reliant’s balance sheet. Reliant

asserts that the Commission’s consolidated tax-savings adjustment amounts to improper retroactive

7
ratemaking and includes companies that should not be part of the calculation. Reliant also complains

that the Commission refused to include overfunding to its retirement plan as part of invested capital

and that it effectively excluded increased reliability expenses.

RATE BASE

A utility’s rate base or invested capital consists of the cost, less depreciation, of

property “used by and useful to the utility in providing service.” See PURA §§ 36.051, .053(a);6 see

also 16 Tex. Admin. Code § 25.231(c)(2) (2003). “‘Used and useful’ refers to ‘such property as has

been acquired . . . in good faith and held for use in the reasonably near future in order to enable [a

utility] to supply and furnish adequate and uninterrupted . . . service.’” Cities, 924 S.W.2d at 935

6
PURA section 36.051 provides as follows:

In establishing an electric utility’s rates, the regulatory authority shall establish
the utility’s overall revenues at an amount that will permit the utility a reasonable
opportunity to earn a reasonable return on the utility’s invested capital used and
useful in providing service to the public in excess of the utility’s reasonable and
necessary operating expenses.

(Emphasis added.) PURA section 36.053 provides as follows:

(a) Electric utility rates shall be based on the original cost, less depreciation, of
property used by and useful to the utility in providing service.

(b) The original cost of property shall be determined at the time the property is
dedicated to public use, whether by the utility that is the present owner or by
a predecessor.

(c) In this section, the term “original cost” means the actual money cost or the
actual money value of consideration paid other than money.

(Emphases added.)

8
(quoting Lone Star Gas Co. v. State, 153 S.W.2d 681, 698 (Tex. 1941)). The Commission has

significant discretion in determining what property is used by and useful to the utility solely to

provide service to its ratepayers; that discretion is even greater for property used for other purposes

with less direct benefit to ratepayers. See El Paso Elec. Co. v. Public Util. Comm’n, 917 S.W.2d

846, 856 (Tex. App.—Austin 1995, writ dism’d). As the United States Supreme Court has written,

“The economic judgments required in ratemaking proceedings are often hopelessly complex and do

not admit of a single correct result.” Duquesne Light Co. v. Barasch, 488 U.S. 299, 314 (1989)

(quoted in El Paso, 917 S.W.2d at 857).

Several parties challenge the Commission’s determination of the rate base for the

Reliant TDU in the forecasted 2002 test year. Reliant questions the propriety of the failure to include

an overfunded retirement plan in the rate base. Other parties challenge the inclusion of facilities in

use at year’s end rather than figuring a year-long average by pro-rating the cost of facilities brought

on line during the year. Gulf Coast complains about the accuracy of the amount of transmission

system costs allotted to a particular plant.

Overfunded Retirement Plan

Reliant argues that the Commission erred by excluding from Reliant’s rate base the

amount in Reliant’s retirement plan exceeding the funds necessary to satisfy its retirement

obligations. Reliant claims that (1) no substantial evidence supports the Commission’s decision and

(2) the decision is arbitrary and capricious because it is inconsistent with previous treatment of

underfunding of Reliant’s retirement fund.

9
Reliant’s witness, James Brian, supported including in Reliant’s rate base the excess

amounts that had accumulated in the retirement plan due to better than expected returns on

investments; Brian projected that the plan would be $40 million overfunded in the forecast test year.7

Brian testified that the overfunding would occur even with no additional contributions from the

company. Brian testified that ratepayers benefit from the excess in that the excess funds reduce

Reliant’s cost of service because Reliant will not have to collect anything in rates to cover

contributions to the retirement plan. He asserted that, because the Commission previously reduced

Reliant’s rate base for underfunding in the retirement plan, the failure to increase Reliant’s rate base

for overages in the retirement plan would be arbitrary and capricious.

Commission staff witness Dinah Arce disagreed with placing the retirement plan

excess in the rate base. She testified that Reliant’s ratepayers had paid into the plan through the

payment of rates and that, according to Brian, the overfunded amounts resulted from investment

returns on the plan balance. Arce then opined that it is not reasonable for Reliant shareholders to

earn an additional return from ratepayers based on the returns on the plan investments.

We conclude that the record contains substantial evidence to support the

Commission’s finding that the overfunded amounts should not be included in Reliant’s rate base.

If a fully funded retirement plan is used and useful in providing electricity, it can be in the rate base.

But previous decisions by the Commission to deduct underfunded amounts from Reliant’s rate base8

7
Brian’s testimony is dated December 2000. Whether the retirement plan remained
overfunded into 2002 is not apparent from the record and is beyond the scope of this review.
8
Though there apparently is no dispute that the Commission in other cases deducted
underfunded amounts from the rate base, our review is restricted to the record before us. See Tex.
Gov’t Code Ann. § 2001.175(e) (West 2000). “We might accurately compare the circumstances in

10
do not make the Commission’s decision to exclude excess funds arbitrary or capricious. Even

assuming, as Reliant argues, that a fully-funded pension plan is an investment that is “used and

useful” in attracting and keeping workers who help supply electric service, the Commission could

reasonably conclude that excess funds are not used or useful in that same way. Excess and deficit

in the same plan do not necessarily represent different sides of the used-and-useful coin. If the plan

is not fully funded, then any deficit can be deducted from the rate base to reflect the company’s

failure to make the full investment necessary to provide the full benefit useful in providing electricity

(e.g., to recruit and retain workers); however, it is not unreasonable to conclude that excess plan

funds are not additionally beneficial or useful in providing electricity and therefore should not be

included in the rate base. Similarly, while lower rates may make purchasing electricity more pleasant

for customers, the Commission could conclude that lower rates are not necessarily used or useful to

the utility in providing service. We overrule Reliant’s fourth issue.

Year-end Rate Base

Gulf Coast, COPS, and OPC each claim that the Commission erred by allowing

Reliant to calculate its rate base using the amount it anticipated investing in transmission facilities

by the end of 2002 (“year-end rate base”); they argue that the Commission should have used the

amount of investment made by midway through the year on June 30, 2002 (“average-year rate base”).

They contend that the use of a year-end rate base violates the PURA requirement that investments

be included in rate base only if they are “used and useful” in providing service. PURA §§ 36.051,

the company’s case with those in the earlier contested cases referred to only if we had before us the
agency record compiled in those other cases.” Public Util. Comm’n v. GTE-Southwest, Inc., 833
S.W.2d 153, 159 (Tex. App.—Austin 1992), rev’d on other grounds, 901 S.W.2d 401 (Tex. 1995).

11
.053(a). They complain that rates could be paid all year long for plant used only on the last day of

the year.

The construction of a statute by the administrative agency charged with its

enforcement is entitled to great weight, as long as the construction is reasonable and does not

contradict the plain language of the statute. State v. Public Util. Comm’n, 883 S.W.2d 190, 196

(Tex. 1994); Dodd v. Meno, 870 S.W.2d 4, 7 (Tex. 1994). The process of setting regulated rates for

utilities is “far from a precise process; instead, ratemaking relies substantially on informed judgment

and expertise and utilizes projections and estimates in virtually all areas.” Public Util. Comm’n v.

GTE-Southwest, Inc., 901 S.W.2d 401, 411 (Tex. 1995).

The mandated use of a forecasted test year makes calculating the rate base even more

speculative. In a traditional rate-setting process, rates are based on a historical test year for which

an objective analysis can be made of what property was acquired and is necessary to provide utility

service. See generally Central Power & Light Co. v. Public Util. Comm’n, 36 S.W.3d 547, 552-53

(Tex. App.—Austin 2000, pet. denied) (“CPL”). But estimates are necessary even when the

ratemaker uses a historical test year. See GTE-Southwest, 901 S.W.2d at 411. Here, the legislature

required the Commission to use the forecasted test year of 2002. See PURA § 39.201(b)(1). Using

a forecasted year means that, unlike when calculating rate base using a historical year, the

Commission had to set rates before the capital additions to be made in the relevant year were

acquired or “used and useful” in supplying electricity.

The City of Houston, Texas Industrial Energy Consumers (“TIEC”), and OPC

sponsored witnesses who supported using the average-year method. Houston’s James Daniel

12
testified that other jurisdictions use average-year to determine rate base for forecasted years. He

testified that using the year-end method would allow Reliant to charge for plant and claim

depreciation on it for up to a year before it was in service or “used and useful.” He said that,

although year-end measures were appropriate for historical test years, they were inappropriate for

a forecasted year. OPC witness Ben Johnson explained that, when using historical test years,

regulatory bodies use year-end balances to better match the level of investment in use during the rate

year because the level of investment on December 31, 2001 is near the level of investment of January

1, 2002. In this case, however, Reliant requested that investment be calculated based on plant

projected to be in use on December 31, 2002 to set rates to be effective on January 1, 2002—almost

a year before the plant was in use. Johnson asserted that this would distort Reliant’s balance sheet

because the rates in place all year would be set for end-of-2002 investment levels, while the revenue

and income stream would represent average conditions throughout 2002. He said that, when

historical test years were used, this revenue/investment mismatch was balanced by a deterioration

in earnings due to inflation, but that the forecasting process should account for inflation in a

forecasted test year. TIEC witness Michael Gorman agreed, testifying that using the average-year

instead of a year-end method would reduce Reliant’s rate base by $192.5 million and lower its

revenue requirement by $24.4 million; Houston’s Daniel estimated a $249 million difference,

resulting in a correspondingly lower revenue requirement.

Reliant witness Brian disputed these witnesses’ testimony. He asserted that an

average-year rate base would create mismatches in the rate-filing package between such items as

accumulated depreciation and depreciated expense. He argued that the Commission should not rely

13
on the possibility of rate correction to address undervaluing of additions to the rate base because the

lag between the application and award of rate changes would further damage the TDUs. Brian also

testified that the year-end method was dictated by the Commission’s instruction in the rate filing

package that stated, “All rate base items for the Forecast Year shall be reflected at the Forecast Year-

end amounts.” Brian argued that the opponents of a year-end rate base should have voiced their

concerns when the instructions were being formulated.

Expressly accepting the testimony of Daniel, Johnson, and Gorman, the ALJ proposed

that the Commission use the average-year rate base, concluding that the average-year rate base would

better match plant investment levels with corresponding expenses than would a year-end calculation.

The ALJ opined that using a year-end measure would allow Reliant to charge customers for plant

that had not yet become used and useful, potentially violating PURA section 36.053. The ALJ

acknowledged that, under the average-year method, Reliant would not be able to recover for its

plant-in-service for years following 2002 until a new ratemaking proceeding, but noted that the

Commission’s rules allowed expedited updating of its rates. See 16 Tex. Admin. Code § 25.193(b)

(2004). The ALJ also wrote, “It has been [Reliant’s] experience in recent years that new revenue has

more than made up for these new expenses under existing rates.”

The Commission, however, rejected the ALJ’s recommendation. The Commission

stated that revenue/investment mismatches were unavoidable when a forecasted year was used. The

Commission opined that, while using a 2002 average balance might somewhat even out the

imbalance over that year, capital additions made during 2002 would be undervalued in the rate base

14
for 2003 and subsequent years until a new ratemaking proceeding is initiated. Therefore, the

Commission allowed Reliant to use a 2002 year-end balance to calculate its projected rate base.

On appeal, Gulf Coast, OPC, and COPS reiterate their argument that the “used and

useful” requirement prohibits use of a year-end rate base because the rates can include capital spent

on facilities that are not in service until late in the year. They contend that this also violates a

principle of matching revenues and expenses. They further complain that the commissioners

considered irrelevant factors in deciding to use the year-end method. They cite comments by

commissioners in the open meeting that the year-end method would provide an incentive for utilities

to build new transmission projects by showing that the Commission was trying to ensure that utilities

could timely recover their investments in such projects. These appellants complain that such

incentives are not proper considerations for inclusion in rate base, and instead violate the

requirement that plant be used and useful to be included in rate base; indeed, Gulf Coast argues that

the rate of return exists to provide the necessary incentive and must not be supplemented by

overstated investment in the rate base. These appellants complain that the Commission’s assertion

that the year-end method better reflects the plant in use for 2003 is based on speculation that there

will not be another ratemaking proceeding for 2003. They contend that the transmission cost

recovery factor (see 16 Tex. Admin. Code § 25.193) exists to incorporate additions to the rate base

without a full-blown ratemaking proceeding.

The Commission can change, modify or vacate an ALJ’s order where the Commission

determines that the ALJ misapplied or misinterpreted Commission rules or policies, applicable law

or prior administrative decisions, or issued a finding of fact not supported by a preponderance of the

15
evidence. See Tex. Gov’t Code Ann. §§ 2001.058(e)(1), 2003.049(g) (West 2000). The

Commission must “state in writing the specific reason and legal basis for its determination” to depart

from the ALJ’s order. See id. § 2003.049(h) (West 2000).

We conclude that appellants have not shown that the Commission erred by adopting

the year-end rate base. The legislature granted the Commission broad powers and discretion in

regulating public utilities. GTE-Southwest, 901 S.W.2d at 409. “An administrative agency is created

to centralize expertise in a certain regulatory area and, thus, is to be given a large degree of latitude

by the courts in the methods by which it accomplishes its regulatory function.” Id. (quoting City of

Corpus Christi v. Public Util. Comm’n, 572 S.W.2d 290, 297 (Tex. 1978)). PURA does not specify

when during the forecasted test year the TDU’s investments must occur in order to be included in

that utility’s rate base. See PURA § 39.201(b)(1). The legislature thus left that decision to the

Commission’s discretion. Further, the supreme court does not always require that plant be in use

in order to be “used and useful” enough to be included in rate base. See Cities, 924 S.W.2d at 941-

42. We find no statutory barrier to the Commission considering whether its rate-base decisions will

encourage investment or how the test-year rate base will affect rates for future years—particularly

in this rare use of a forecasted year for the unique purpose of regulating the unbundling of electric

utilities to facilitate the transition from a regulated market to a competitive market. In this context,

the Commission’s decision that the 2002 year-end rate better reflects the plant used and useful for

2002 and for 2003, during which time the rates will also be in effect—essentially creating an

average-two-year method—is not erroneous.

We overrule Gulf Coast’s third issue, OPC’s second issue, and all of COPS’s issues.

16
Merchant Plant 4

Gulf Coast argues that the Commission overstated Reliant’s transmission system

capital costs by relying on a cost estimate of a particular project by a witness who in rebuttal reduced

his estimate of the cost of that same project. Gulf Coast does not on appeal challenge the

Commission’s inclusion of costs for interconnecting Merchant Plant 4, but disputes the amount

included. Gulf Coast would rely on the revised estimate rather than the original estimate.

In March 2000, Reliant witness John Houston testified about expenditures necessary

for the continued operation of Reliant’s transmission delivery system and the effect of the

interconnection of new merchant generators to the Reliant transmission system. He estimated that

$300 million of the approximately $482 million to be spent on the transmission system during the

years 2000-02 would be devoted to the interconnection of merchant generators to the Reliant

transmission system. The City of Garland submitted a workpaper bearing Houston’s initials

containing an estimate that the interconnection of Merchant Plant 4 would cost $107.3 million.

In testimony dated December 12, 2000, COPS witness Brian Gedrich asserted that

he did not believe that Reliant would incur all the costs claimed. He opined that the market would

not demand all the capacity that Reliant projected by the end of 2002. In a chart, he used Houston’s

estimate that Merchant Plant 4 would cost $107.3 million, but then listed that amount under the

column heading “$ Excluded.”

In his rebuttal testimony, dated December 29, 2000, Houston testified that the

transmission cost estimates had changed. Some had increased because of demand but others

decreased because new technology allowed Reliant to increase the capacity of existing transmission

17
corridors, reducing the need for new transmission construction. Houston said that the new

technology eliminated the need to construct a relief circuit to interconnect Merchant Plant 4.

Houston said:

Originally, we estimated that the entire interconnection would cost approximately
$107.3 million, including approximately $42.5 million for the Greens Bayou-White
Oak Project. The project is now estimated to cost $50.2 million. If we had not been
able to use the new ACSS conductor technology on the King-North Belt circuits, and
a 345 KV Greens Bayou-White Oak circuit was still needed, then the estimated cost
would be $92.7 million, roughly 14% below the original estimate.

This testimony was uncontroverted.9 Houston further testified that, despite the decrease in the

amount attributed to the Merchant Plant 4 interconnection, increased demand caused him to revise

his estimate of Reliant’s overall projected interconnection costs upward by $96.4 million over his

original estimates. Reliant did not request additional funds based on this new estimate, but used the

revised estimates to bolster its position that its original estimate was reasonable.

In the proposal for decision (“PFD”) dated March 27, 2001, the ALJ recommended

that the Commission not include in Reliant’s transmission system capital costs any of the costs

associated with the Merchant Plant 4. The ALJ wrote, “Nobody pretends to know which plants will

and will not actually be built by the end of 2002, but the ALJ finds that COPS witness Mr. Gedrich

drew the most reasonable line.” The ALJ then used Gedrich’s table listing the to-be-excluded cost

9
Although the quoted passage may be ambiguous in isolation regarding which “project” is
estimated to cost $50.2 million, the context shows that the relevant project is the Merchant Plant 4
interconnection. Houston stated that new technology had increased the capacity of existing
transmission facilities, rendering building the Greens Bayou-White Oak circuit (which he estimated
would cost $42.5 million) unnecessary. Reducing the revised cost estimate of $92.7 million for
Merchant Plant 4 by the $42.5 million cost of the unnecessary circuit leaves $50.2 million.

18
of Merchant Plant 4 as $107.3 million, based on Houston’s original testimony; the ALJ did not

explain the use of the original Merchant Plant 4 estimate rather than the revised estimate.

The Commission, however, rejected the ALJ’s recommendation to exclude the costs

of interconnecting Merchant Plant 4 during the relevant time period. The Commission added $107.3

million, the exact amount Houston originally estimated, ignoring his revised estimate, for the cost

of the Merchant Plant 4 interconnection.

The issues raised for a reviewing court when an agency rejects uncontradicted

evidence are complex. See Cities of Port Arthur v. Railroad Comm’n, 886 S.W.2d 266, 270 (Tex.

App.—Austin 1994, no writ). An administrative agency’s decision is to be based on evidential facts

and made by experienced officials with an adequate appreciation of the complexities of the subject

which is entrusted to their administration. Id. But an agency is not obliged to accept opinion

testimony from an expert—even if it is the sole evidence on the issue and is uncontradicted and

unimpeached. See Fuel Distrib., Inc. v. Railroad Comm’n, 727 S.W.2d 56, 61 (Tex. App.— Austin

1987, writ ref’d n.r.e.). We must uphold an agency’s finding even if the evidence actually

preponderates against the agency’s finding so long as enough evidence suggests the agency’s

determination was within the bounds of reasonableness. Southwestern, 962 S.W.2d at 215.

Gulf Coast claims that the Commission’s inclusion of $107.3 million for the

Merchant Plant 4 interconnection costs is not supported by substantial evidence. Gulf Coast argues

that Houston’s original testimony is the only source of the $107.3 million estimate, and that his

revised estimate—the validity of which is unchallenged—renders the original estimate essentially

a nullity. Gulf Coast contends that the ALJ used the $107.3 million estimate only because it adopted

19
Gedrich’s summative chart, and probably did not amend the chart with Houston’s revised estimate

because the revision did not affect the ALJ’s recommendation that no costs associated with the

Merchant 4 plant be awarded.

Reliant and the Commission argue that we may examine only the overall allocation

of $261.2 million in finding 33A for service to new generators as well as the total of all projected

capital expenditures. Reliant argues that it is inequitable to consider only the forecasted reductions

for Merchant Plant 4, but not increases in other transmission costs that outstrip the Merchant Plant

4 savings in deciding whether the evidence supports the Commission’s order.

The Commission may depart from ALJ recommendations so long as it explains its

departure. Tex. Gov’t Code Ann.§ 2003.049 (g),(h) (West 2000). Houston’s increased estimates

of overall costs could support an increase attributable to other expenses, but the Commission’s

explanation for its departure from the ALJ’s recommendation was not that overall capital

expenditures had increased, but that Merchant Plant 4 costs must be included. It is significant that

the Commission included $107.3 million, the figure Houston originally gave for Merchant Plant 4,

not the $96.4 million he attributed to other transmission cost increases, or some other figure. The

Commission’s order is clear that the upward revision of the interconnection costs was due, not to a

general increase in such costs,10 but solely to the inclusion of Merchant Plant 4 interconnection costs:

In evaluating the ten planned merchant generator interconnection projects that Reliant
sought to include in its rate base, the ALJs considered whether the generator
requesting the service had made a substantial irrevocable commitment to the

10
To the extent that Reliant believed the Commission erred by not raising the general
allocation of interconnection costs, it has failed to raise that error for our review.

20
transmission project. The Commission agrees with the standard used by the ALJs,
but finds that Merchant Plant 4 sufficiently meets the standard of substantial
irrevocable financial commitment. Findings of Fact Nos. 33 and 34 are deleted and
new Findings of Fact Nos. 33A and 34A are added and reflect the inclusion of $107.3
million for this project.

Reliant Order at 57 (emphasis added). But Houston clearly and unequivocally stated in rebuttal to

his own testimony that the project would cost only $50.2 million. He revised his calculation, not

because of discovered mistakes or a changed opinion regarding the necessity of interconnecting

Merchant Plant 4, but because technological advancement meant that a $42.5 million component of

the original interconnection plan would not be built. This declaration is highly credible because

Houston was the Vice President of Transmission and Substation Operations for Reliant Energy

HL&P, and nothing in the record rebuts his assertion that Reliant would not build the new

transmission line. The Commission’s findings, inferences, conclusions, or decisions must be

supported by substantial evidence from the record as a whole. Tex. Gov’t Code Ann.

§ 2001.174(2)(e) (West 2000). Although deference is due the agency’s findings of fact, the nature

of Houston’s rebuttal, the lack of any contradiction or impeachment of his evidence, and the way in

which the Commission derived the figure persuade us that no evidence supports the finding that the

interconnection of Merchant Plant 4 would cost $107.3 million. The allocation of money based on

non-existent needs for Merchant Plant 4 cannot be supported by evidence that would support

allocation of a greater amount of money for other expenditures. The Commission could have

allocated money for those expenditures, but it did not; its order plainly states that it allocated money

for costs associated with Merchant Plant 4.

21
In light of Houston’s uncontroverted downward revision of his estimate of Merchant

Plant 4's interconnection costs, no reasonable basis existed to use the original estimate in

determining Reliant’s transmission system capital costs. We hold that the Commission’s inclusion

of $107.3 million associated with interconnection costs for Merchant Plant 4 in its final order is not

supported by substantial evidence. We sustain Gulf Coast’s first issue, reverse the inclusion of

$107.3 million for the interconnection of Merchant Plant 4, and remand this issue to the Commission

for further proceedings. See Tex. Gov’t Code Ann. § 2001.174(2)(E). On remand, the Commission

must base its decision on the existing administrative record. See Texas Health Facilities

Commission v. Nueces County Hospital Dist., 581 S.W.2d 768, 770 (Tex. Civ. App.—Austin 1979,

no writ); First Sav. & Loan Assoc. v. Lewis, 512 S.W.2d 62, 64 (Tex. Civ. App.—Austin 1974, writ

ref’d n.r.e.).

RETURN ON EQUITY

Gulf Coast and OPC raise several complaints on appeal regarding the determination

of the return on equity. They argue that the consolidation of the determinations of the rates of return

for several utilities into a single proceeding producing a generic return on equity for those utilities

is not supported by law or substantial evidence. They argue that the generic proceeding was

unlawful because the Commission did not make utility-specific determinations as required by PURA

section 36.052. They also contend that the Commission’s failure to adjust the return on equity

despite the substantial decline in the cost of capital results after the interim generic order but before

the Reliant-specific order resulted in an inflated, unreasonable return on equity in violation of PURA

section 36.051.

22
PURA requires that the Commission set a “reasonable” return on the utility’s invested

capital. PURA § 36.051. In setting this return, the Commission “shall consider applicable factors,

including: (1) the efforts and achievements of the utility in conserving resources; (2) the quality of

the utility’s services; (3) the efficiency of the utility’s operations; and (4) the quality of the utility’s

management.” PURA § 36.052. The Commission is not limited to considering these four factors;

the statute merely includes these four factors among the applicable factors. See id. Although the

Commission was required to consider the listed factors, it was not required to make “ultimate”

findings on each issue. See Meier Infiniti Co. v. Motor Vehicle Bd., 918 S.W.2d 95, 100 (Tex.

App.—Austin 1996, writ denied). “[T]he logical force of the findings of underlying fact must be

such that the reviewing court can fairly and reasonably say that the underlying findings support the

statutorily required criteria.” Id.

Return on equity is among the issues in the utility restructuring process that the

Commission concluded could be most efficiently and appropriately resolved in a generic proceeding

involving all the newly unbundled TDUs.11 The Commission found underlying similarities among

the unbundled TDUs—including the level of regulatory oversight and comparable levels of

risk—and concluded that a generic proceeding generating a generic return on equity for the TDUs

was appropriate. In the generic proceeding, the Commission left open the possibility of

individualized returns on equity, but in this proceeding applied the generic return for Reliant. The

11
In order to develop a list of issues to be considered in this proceeding, the Commission
directed all parties to file a list of issues to be addressed and to separately identify those issues
generic to all unbundled cost of service filings. Parties were also encouraged to identify any issues
that should not be addressed in the generic proceeding.

23
Commission considered the recommendation by some parties in a non-unanimous stipulation and

agreement of a 10.75% return as a reasonable starting point. Texas Pub. Util. Comm’n, Generic

Issues Associated with Applications for Approval of Unbundled Cost of Service Rate Pursuant to

PURA § 39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22344, Order

No. 42, at 11 (Dec. 22, 2000). This number lies in the middle of the ranges of reasonable returns on

equity admitted into evidence. Id. The Commission decided to add 0.5% to the stipulated return on

equity to account for factors such as the undetermined effect of higher debt (based on the adoption

of 60% debt and 40% equity for capital structure in this proceeding) on the TDUs’ investment-risk

ratings and the risk premium recalculation recommended by Commission staff witness Martha

Hinkle. Id. Accordingly, the Commission approved a return on equity of 11.25%. Id.

Propriety of a generic proceeding

We first consider the broad issue of whether the Commission is authorized to conduct

a generic proceeding to determine a single issue common to several utilities. The Commission has

“the general power to regulate and supervise the business of each public utility within its jurisdiction

and to do anything specifically designated or implied by this title that is necessary and convenient

to the exercise of that power and jurisdiction.” PURA § 14.001. The Commission has the power

to call and hold hearings and to adopt and enforce rules reasonably required to exercise its power and

jurisdiction. See id. §§ 14.002, .051, .052. OPC argues that, because the Commission did not enact

a procedural rule for considering an issue common to several utilities in a generic proceeding, the

Commission could not do so. But the Commission’s rules permit severance of proceedings or issues

if the severance would serve the interest of efficiency or prevent unwarranted expense and delay.

24
16 Tex. Admin. Code § 22.34(b) (2004). Proceedings may be consolidated if the proceedings

involve common questions of law or fact and consolidation would be more time and cost efficient.

Id. § 22.34(a). OPC seizes on the omission of the word “issues” from the consolidation provision

to argue that issues cannot be consolidated. We are not persuaded by this distinction. If Issue A

from one docket can be heard with Issue B from another docket when the two dockets are

consolidated, we see no reason that the Commission could not, after severing issues A and B from

their respective dockets, consolidate its consideration of issues A and B. For purposes of rule 22.34,

the severed issues in essence become “proceedings” of their own that can be consolidated.

Even if rule 22.34 were insufficient on its own terms, this Court has recognized that

the Commission has the power to control its own docket. City of El Paso v. Public Util. Comm’n,

839 S.W.2d 895, 926 (Tex. App.—Austin 1992), rev’d in part on other grounds, 883 S.W.2d 179

(Tex. 1994). In that case, despite the absence of a rule expressly allowing severance, we found

authority to sever in the Commission’s broad regulatory power and attendant powers necessary for

efficient conduct of adjudicative hearings. Id.; see also Public Util. Comm’n v. Southwestern Bell

Tel. Co., 960 S.W.2d 116, 119 (Tex. App.—Austin 1997, no pet.). In El Paso, we wrote, “Any other

result would defeat the legislative intent in delegating duties to the Commission for more efficient

administration.” 839 S.W.2d at 926. This Court has recognized that the legislature delegated to the

Commission broad powers:

A delegation of power to an administrative agency, in such broad and general terms,
implies a legislative judgment that the agency should have the widest discretion in
conducting its adjudicative proceedings, including a discretion to make ad hoc
rulings in specific instances, within the bounds of relevant statutes and the
fundamentals of fair play.

25
Southwestern Bell, 960 S.W.2d at 119. The agency must have the flexibility to adjust to the variety

of incidents encountered in particular contested cases. Id. We conclude that the Commission has

the authority to consolidate issues severed from different dockets into a single generic proceeding.

OPC and Gulf Coast argue that the record lacks substantial evidence to support the

conclusion that there are sufficient similarities among the TDUs to support consolidation of their

return-on-equity proceedings into a single proceeding producing a single generic return on equity.

It is undisputed that the TDUs are all new, spawned by the unbundling required by the statutes

governing the move from a regulated environment to a competitive one. See PURA § 39.051(b).

Thus, as independent companies, they share the same history—none. Commission staff witness

Martha Hinkle testified12 that TDUs share a reduction of risks by being separated from other aspects

of the power industry. They would not be subject to risks from asset concentration due to owning

generation facilities or risk that generating plants would run into regulatory difficulties. Further,

their cash flow would be more stable than an integrated utility’s because they would not be subject

to fuel-price fluctuations and because transmission and distribution are essential services. She

testified that all TDUs would have risk ratings in the lower half of the business position risk

assessment range (1 to 4 on a 10-point scale), in contrast to the existing integrated companies which

were in the mid-range of risk (4 to 7; Reliant Energy had a rating of 6). She testified that TDUs

12
There is some criticism that Hinkle testified in November, well after the Commission
decided to determine the generic return on equity, and therefore could not supply evidence to support
the decision to use the generic proceeding. However, the interim order authorizing the generic
proceeding left open the possibility of individualized determinations. Because Hinkle’s evidence
apparently helped dissuade the Commission from conducting such individual determinations, we can
consider whether it supports the Commission’s decision to develop a generic rate.

26
would have similar risk profiles because of similarities in their business and regulatory risks,

although differences would persist in the types of territory served, growth rates, and corporate

structures. She opined that the differences in risk profiles “will not lead to the disparate bond ratings

that have resulted from the risk associated with providing generating facilities.” The Commission

even left open the possibility of setting individualized rates of return, and even set one TDU’s return

determination into a separate docket; however, the parties challenging the use of the generic rate in

this appeal did not cite any evidence in their briefs supporting using an individualized rate for

Reliant’s TDU beyond promoting a different interpretation of Hinkle’s testimony—particularly her

admission that differences exist among the TDUs. The Commission’s decision to use a generic

proceeding to set a return on equity for all the TDUs was supported by substantial evidence.

Appropriateness of the generic return for Reliant’s TDU

Gulf Coast and OPC further contend that the Commission acted arbitrarily and

capriciously by using the generic return on equity for Reliant without considering the utility-specific

factors listed in PURA section 36.052: the TDU’s efforts and achievements in conserving resources,

the quality of its services, the efficiency of its operations, or the quality of its management. Although

Reliant argues that evidence on these issues was before the Commission, in its brief the Commission

concedes that it did not consider the listed factors; instead, the Commission argues that the factors

relate to a utility’s historical practices, which the newly unbundled TDU does not have. Gulf Coast

and OPC contend that the statute requires the Commission to consider these factors. See PURA

§ 36.052. They also note that the TDU has a history as part of Reliant that could be examined to

assess the unbundled TDU’s prospects regarding the listed factors.

27
In determining whether an agency act or omission is arbitrary and capricious, a

reviewing court must ascertain whether the agency abused its discretion by basing its decision on

legally irrelevant factors, or by omitting to consider factors that the legislature statutorily directs the

agency to consider. Consumers Water, Inc. v. Public Util. Comm’n, 774 S.W.2d 719, 721 (Tex.

App.—Austin 1989, no pet.) (citing Gerst v. Nixon, 411 S.W.2d 350, 360, n.8 (Tex. 1966)). An

agency is not required to make ultimate findings as to each factor listed in the statute. See Meier,

918 S.W.2d at 100. The factors listed in section 36.052 are not exclusive. See Cities of Abilene v.

Public Util. Comm’n, 854 S.W.2d 932, 942 (Tex. App.—Austin 1993), rev’d in part on other

grounds, 909 S.W.2d 493 (Tex. 1995). In its order adopting the generic return on equity, the

Commission stated that it considered the following factors: (1) the levels of business and financial

risk; (2) the Commission’s decisions in the rate design phase of this case; (3) the need to maintain

reasonable rates; (4) the need for new transmission capacity; (5) the maintenance of adequate

reliability standards; and (6) the companies’ ability to attract new capital. Reliant Order at 24. The

Commission also noted that this proceeding was to set rates for the period of transition to a more

competitive energy market.

We conclude that the Commission did not act arbitrarily or capriciously by not

considering the factors listed in 36.052. The evidence and findings that the TDUs have a degree of

uniformity supports the decision not to explore the issues in a utility-specific matter in every case

(although the Commission’s generic order did leave open that possibility). But the stronger support

comes from the fact that these TDUs are creatures born of the transition to competitive markets. The

evidence and finding that the new TDUs have reduced risk profiles supports a conclusion that they

28
are different from when they were part of a larger utility. More critically, the statutory mandate

creating the TDUs made it impossible to assess the TDUs’ conservation efforts and achievements

and the quality and efficiency of their services, operations and management because the TDUs have

no record as standalone entities. Although this is not a direct statutory conflict—i.e., PURA section

36.052 does not prevent unbundling—the unbundling mandated by PURA section 39.051 has

rendered impossible a duty created by PURA section 36.052; in such instances, Chapter 39

provisions control. See PURA § 39.002. We conclude that, under the circumstance of the inception

of the TDUs as part of the transition to competitive markets, the Commission did not err by failing

to consider nonexistent factors in calculating a reasonable return on equity.

Failure to reopen record to adjust return for falling interest rates

Gulf Coast further complains that the return on equity of 11.25% is not reasonable

because it fails to account for the Federal Reserve Board’s repeated reductions of short-term interest

rates between December 18, 2000 (the date of the Commission’s decision in the generic proceeding

setting the return on equity at 11.25%) and October 3, 2001 (the date of the final order in the Reliant-

specific case). Gulf Coast reiterates on appeal its claim made in its motion for rehearing below that

the Commission should have held another hearing to determine the effect of the interest rate changes

on the reasonableness of the return on equity.

Whether to reopen an administrative record to allow additional evidence is generally

a matter left to the discretion of the Commission. Lake Medina Conservation Soc’y v. Texas Natural

Res. Conservation Comm’n, 980 S.W.2d 511, 518-19 (Tex. App.—Austin 1998, pet denied); City

of El Paso v. Public Util. Comm’n, 609 S.W.2d 574, 578 (Tex. Civ. App.—Austin 1980, writ ref’d

29
n.r.e.). In a similar case under federal administrative law involving a five-year gap between receipt

of evidence and the decision, the Supreme Court held that the delay did not make the record too stale

to support an administrative decision, stating:

Administrative consideration of evidence . . . always creates a gap between the time
the record is closed and the time the administrative decision is promulgated. If upon
the coming down of the order litigants might demand rehearings as a matter of law
because some new circumstance has arisen, some new trend has been observed, or
some new fact discovered, there would be little hope that the administrative process
could ever be consummated in an order that would not be subject to reopening. It has
been almost a rule of necessity that rehearings were not matters of right, but were
pleas to discretion. And likewise it has been considered that the discretion to be
invoked was that of the body making the order, and not that of a reviewing body.

Bowman Transp., Inc. v. Arkansas-Best Freight Sys., Inc., 419 U.S. 281, 294-95 (1974) (quoting

Interstate Commerce Comm’n v. Jersey City, 322 U.S. 503, 514-515 (1944)). In Bowman, the

Supreme Court noted it had found an abuse of discretion for the failure to reopen the record of a

proceeding to account for the “economic metamorphosis” wrought by the Great Depression.

Bowman, 419 U.S. at 295 (citing Atchison, T. & F.R. Co. v. United States, 284 U.S. 248 (1932)).

But the Supreme Court also noted several cases of relatively similar vintage in which it did not find

an abuse of discretion. See Bowman, 419 U.S. at 295.

Reliant argues that other factors affecting rates also changed in the same period (they

assert that natural gas prices affecting excess mitigation credits declined by 50%); Reliant also notes

that Gulf Coast did not seek to supplement the record with the interest rate changes until after the

October 2001 order. Gulf Coast responds that the interest rate drop was unprecedented, that no other

party requested to revisit any other component of the rates, and that their October 29, 2001 motion

30
for rehearing gave the Commission plenty of time to hold a hearing, based on the previous one-day

return-on-equity hearing on November 6, 2000.

We find the reasoning in Bowman persuasive. The parties’ arguments regarding

various changes in market forces show why the decision on whether to reopen the record is

committed to the Commission’s sound discretion. Interest rates are subject to change and the failure

of rates set through a regulatory process to keep pace with interest rate changes is inherent in the

regulatory process. In this case, utility rates had to be set by January 1, 2002. Given the complexity

of the rate-setting hearing and the imminence of the period for which rates were to be set, we cannot

find that the Commission abused its discretion in not reopening the record to take into account

changes in interest rates that occurred after the administrative record had closed.

We overrule Gulf Coast’s second issue and OPC’s third issue.

REASONABLE AND NECESSARY EXPENSES

In setting the Reliant TDU’s rates, the Commission considered the company’s

reasonable and necessary expenses. Reliant complains that the Commission’s calculation of its

consolidated tax savings and application of a generic escalator to its vegetation control costs made

its rates too low. Gulf Coast assails the Commission’s failure to use surplus insurance funds to

reduce the TDU’s rates.

Consolidated Tax Savings

Reliant argues that the method the Commission used to determine the TDU’s fair

share of consolidated tax savings constitutes impermissible retroactive ratemaking, erroneously

31
includes the losses of companies that will not be eligible to file a consolidated tax return with the

TDU, and arbitrarily and capriciously fails to follow methods used in similar cases

Federal income tax is one of the “reasonable and necessary expenses” that a utility

incurs in providing service to ratepayers. See 16 Tex. Admin. Code § 25.231(b)(1)(D); GTE-

Southwest, 901 S.W.2d at 409. When considering income taxes as part of a utility’s cost of service,

PURA requires the Commission to determine a utility’s “fair share” of the tax benefits that result

when its parent company files a consolidated tax return:

(a) Unless it is shown to the satisfaction of the regulatory authority that it was
reasonable to choose not to consolidate returns, an electric utility’s income taxes
shall be computed as though a consolidated tax return had been filed and the
utility had realized its fair share of the savings resulting from that return, if:

(1) the utility is a member of an affiliated group eligible to file a consolidated
income tax return; and

(2) it is advantageous to the utility to do so.

PURA § 36.060(a). The legislature has granted the Commission broad discretion in determining a

utility’s fair share of the savings arising from the filing of a consolidated tax return by the parent

company. CPL, 36 S.W.3d at 554. A consolidated return can result in tax savings because one

company’s income may be offset by the losses of affiliated companies, reducing the tax liability for

the collective affiliated group. See id. at 555.

Reliant argues that the Commission’s application of the consolidated tax savings

adjustment in this case constitutes impermissible retroactive ratemaking because it adjusts for tax

savings over a previous 15-year period—years in which the Commission had already apportioned

32
fair shares of the tax savings. Utility rates are set prospectively, and the Commission “may not set

rates that allow a utility to recoup past losses or refund excess utility profits to consumers.” Id. at

554; see also Tex. Const. art. I, § 16. Reliant argues that the orders in the previous rate-setting cases

are final and cannot be re-litigated in this case.

We discussed and rejected Reliant’s arguments when we reviewed the Commission’s

similar analysis in CPL. See 36 S.W.3d at 554-57. We concluded then that, “[a]s long as the

Commission is not trying to recoup past savings, but only trying to recover today's benefit from those

past savings, its calculation of consolidated tax savings does not constitute retroactive ratemaking.”13

Id. at 557. Reliant’s attempt in its appellant’s brief to distinguish the discussion in CPL about

retroactive ratemaking as dicta fails; the issue was central to the resolution of the appeal in CPL.

See id. at 556-57. We decline Reliant’s request that we overturn our decision in CPL. The reasoning

in that case applies to the arguments and evidence presented in this case. We overrule Reliant’s first

issue.

Reliant also argues that its TDU should not be subject to the adjustment because some

of the companies whose losses were used to calculate the Commission’s consolidated tax savings

13
The methodology at issue is the time-value-of-tax-shield methodology. See CPL, 36
S.W.3d at 555-56. This formula initially calculates fifteen years’ worth of savings enjoyed by the
parent company as a result of using its profitable affiliates’ gains to utilize the tax benefits of its
unprofitable affiliates’ losses. Then, looking at the gains of each subsidiary standing alone, the
Commission calculated which of those losses would have been offset by the subsidiary’s own gains
during that fifteen-year period. The remaining losses—losses that would have had no value to the
parent during the fifteen-year period if one of its affiliates had not earned profits against which those
losses could be applied—were multiplied by the percentage that represents the affiliate’s share of
the parent company’s overall profits during those years. The resulting figure was multiplied by the
affiliate’s long-term debt rate, resulting in the consolidated tax savings to the affiliate. Id. at 556.

33
adjustment will not be affiliated with the TDU during the forecast year of 2002, and therefore would

not be eligible to file a consolidated tax return with the TDU. Reliant argues that the losses of the

non-affiliated companies should be deducted from the amount used to calculate the consolidated tax

savings adjustment. However, the TDU’s affiliations during the forecast test year are not relevant

to the consolidated tax savings calculation because, as discussed in CPL, the Commission adjusted

forecast rates based on the value of a benefit that the Commission has determined the TDU

possesses. See CPL, 36 S.W.3d at 555-57. It is a calculation based, not on affiliations in 2002, but

on an economic advantage that the Commission has determined that the TDU possesses and from

which ratepayers are entitled to benefit in the test year. See id. Reliant’s complaint fails.

Reliant further argues that the adjustment approved by the Commission is arbitrary

and capricious because it differs from the treatment of other utilities ordered by the Commission in

other proceedings. We must reverse the Commission’s order if the Commission’s action was

arbitrary or capricious. See Tex. Gov’t Code Ann. § 2001.174(2)(F); Public Util. Comm’n v. Gulf

States Utils. Co., 809 S.W.2d 201, 210-11 (Tex. 1991). An agency decision is arbitrary when its

final order denies parties due process of law, see Lewis v. Metropolitan Sav. & Loan Ass’n, 550

S.W.2d 11, 16 (Tex. 1977), or when it fails to follow the clear, unambiguous language of its own

regulations. Gulf States, 809 S.W.2d at 207; Power Res. Group, Inc. v. Public Util. Comm’n, 73

S.W.3d 354, 358 (Tex. App.—Austin 2002, pet. denied). A court reviewing a decision for

arbitrariness should consider all relevant factors and may not substitute its judgment for that of the

agency. See Gulf States, 809 S.W.2d at 211. Our review is limited to determining whether the

administrative interpretation “is plainly erroneous or inconsistent with the regulation.” Id. at 207.

34
Reliant complains that the Commission’s decisions in this case regarding the

consolidated tax savings adjustment differ from its treatment of other utilities in similar

circumstances in three areas. Reliant complains that the Commission applied a gross-up factor14 to

its tax savings amount, despite not applying the same factor in CPL; thus, instead of adjusting for

$19.1 million of tax savings, the Commission “grossed-up” that figure to $29 million. Reliant

complains that the Commission failed to distinguish between companies and divisions as it did in

CPL; Reliant contends that, as a result, the Commission overstated the former affiliates’ losses

because some of the losses occurred in divisions and should have been used to offset profits from

other divisions in the same company, thus drastically reducing the amount of tax savings the

Commission should have found that the TDU accrued. Finally, Reliant complains that the

Commission used the tax savings to reduce the TDU’s operating expenses instead of reducing the

rate base, as the Commission did in a similar proceeding involving TXU; Reliant argues that the

different treatments reduced its income by nine times more than if it had been treated like TXU.

Two of Reliant’s complaints rely on a comparison of the Commission’s treatment of

Reliant to its treatment of other utilities in different proceedings. But our review is restricted to the

record before us, and an accurate comparison of this case to the earlier cases is not possible without

at least relevant portions of those records or agreed statements of the circumstances of and arguments

made in those cases. Tex. Gov’t Code Ann. § 2001.175(e) (West 2000); Public Util. Comm’n v.

14
Reliant explains in its appellant’s brief that the gross-up factor is an adjustment made to
negate the effect of taxes: “For example, a party who receives $100 will have to pay approximately
$35 in taxes, and thus will have net revenues of only about $65 absent a gross-up. To ensure a net
amount of $100 after taxes, the party must be allowed to recover approximately $154.”

35
GTE-Southwest, Inc., 833 S.W.2d 153, 159 (Tex. App.—Austin 1992), rev’d on other grounds, 901

S.W.2d 401 (Tex. 1995). Reliant concedes that those records are not before us but argues that such

records would be unwieldy and possibly inadmissible in this proceeding. Rendering those concerns

moot, however, is the inaccuracy of the premise underlying Reliant’s argument that the

Commission’s different treatment of other utilities in other cases necessarily means that its treatment

of Reliant in this case is arbitrary and capricious. Even if we had the records of the other

proceedings before us, the question would remain whether the arbitrariness and capriciousness

manifested itself in this case, the other case, neither, or both. In short, regardless of the

Commission’s actions in other cases and the presence of the records of those cases, we must assess

the reasonableness of the treatment of Reliant by the record in this case.

The only evidence in this record supports application of the gross-up factor. OPC

witness Candice Romines testified that the gross-up factor was necessary to adjust for the effect of

taxes. Although Reliant disagrees vehemently with this calculation as part of what it deems

retroactive ratemaking, it points to no evidence disputing her testimony or showing that application

of a gross-up factor is inherently arbitrary or capricious; as to the gross-up factor, Reliant argues only

that its application here is an impermissible divergence from the procedure used for CPL in its

proceeding.15 The record in this case, however, does not show that the divergence is unjustified.

Romines’s testimony in this case supports the use of the gross-up factor and makes the

Commission’s use of the factor in this case neither arbitrary nor capricious.

15
No party challenges Reliant’s assertion that the gross-up factor was not used in CPL; the
term “gross-up” does not appear in our CPL opinion. See generally, 36 S.W.3d at 547-72.

36
Reliant next complains that the Commission unfairly calculated Reliant’s

consolidated tax savings adjustment by considering losses at the division-wide level rather than at

the company-wide level, as it had done with CPL. Reliant argues that certain divisions reported

losses that were offset by gains in other divisions within the same company, but that the

Commission’s failure to combine these divisions’ gains and losses caused the Commission to

overstate the size of the overall business entity’s total losses and, hence, the size of the necessary

adjustment. OPC argues that differences in corporate structure between Reliant and CPL make a

strict application of the CPL method not feasible; OPC’s assertion is undisputed, although no party

cites evidence of the asserted differences in corporate structure. The record does not demonstrate

that calculation of gains and losses at the division level, rather than the company-wide level, is

arbitrary or capricious in this case.

Similarly, the record does not weigh against the use of the consolidated tax savings

adjustment amount to reduce Reliant’s operating expenses. Without pointing to evidence in this

record of TXU’s treatment, Reliant complains without contradiction that the Commission reduced

TXU’s rate base instead of its operating expenses, resulting in disparate impact on the tax

adjustments of the two companies. Reliant calculates that, assuming a $30 million dollar adjustment,

applying the adjustment to its operating expenses reduced its income by about $30 million, while

using it to reduce rate base as was done with TXU would have reduced Reliant’s income by only $3

million. Reliant does not argue and points to no evidence in this record showing that applying the

adjustment to operating expenses is, in itself, arbitrary or capricious. Assuming arguendo that TXU

and Reliant were treated differently does not establish that the treatment of Reliant was arbitrary or

37
capricious. Perhaps the treatment of TXU is improper, or perhaps neither is improper. We conclude

that Reliant has not shown error on this record.

We overrule Reliant’s second issue.

Vegetation Control Costs

In its third issue, Reliant argues that the Commission’s decision not to exempt its

vegetation control expenses from the generic cost escalation factor is not supported by substantial

evidence and is arbitrary and capricious. To set TDU rates based on estimated expenses, the

Commission took expenses from the test year of 1999, then applied four generic escalation rates to

different classes of expenses; the escalators permitted an overall increase in expenses of about 1.8%

per year. The Commission exempted some expenses from the limitation of this generic rate,

however, because they were “new” expenses created by unbundling; these new expenses include

demand-side management expenses, transmission access charges, and corporate restructuring costs.

See Tex. Pub. Util. Comm’n, Generic Issues Associated with Applications for Approval of

Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and Public Utility Commission

Substantive Rule 25.344, Docket No. 22344, Order No. 25, (Aug. 24, 2000) (hereinafter, Generic

Order No. 25).

Reliant argues that the Commission also should have excluded vegetation control

costs from the generic escalation rate because those costs will rise sharply due to higher reliability

standards set by the legislature and implemented by the Commission. See generally PURA § 38.005;

16 Tex. Admin. Code § 25.52(f) (2004). Reliant argues that the new standard quintuples the

38
previous standard16 and effectively doubles even Reliant’s heightened internal standard. Reliant

argues that the Commission acted arbitrarily and capriciously and without support in the record by

treating the additional vegetation control costs differently from other new charges, such as demand-

side management costs. Reliant argues that the Commission’s decision violated the requirement that

utilities have a reasonable opportunity to recover a reasonable return on their investments that

exceeds their expenses. See PURA § 36.051.

Before reviewing the Commission’s order, we must determine the scope of our review

of the record. The parties, including Reliant, cite evidence and testimony from both the generic

proceeding and the Reliant-specific proceeding in support of their arguments regarding the

Commission’s decision to apply generic escalators. Reliant, however, argues in its appellant’s reply

brief that evidence adduced in the Reliant-specific proceeding after the Commission’s August 2000

order in the generic proceeding was not before the Commission when it made the August 2000 order.

This argument is especially compelling because of the following language in the August 2000 order:

[T]he resolution of an issue in this generic proceeding is to be applied in each
utility’s UCOS proceeding. Issues that are resolved in this proceeding will not be
litigated or re-litigated in the utility-specific UCOS cases other than as specified by
an order issued in this proceeding.

16
Compare 16 Tex. Admin. Code § 25.52(f)(2)(A) (2004) (no distribution feeder shall be
among system’s worst 10% for service interruption in consecutive years), with 23 Tex. Reg. 11921,
11930 (1998) (setting out former 16 Tex. Admin. Code § 25.51(g)(2)(C) (no distribution feeder shall
be among system’s worst 2% for service interruption in consecutive years).

39
Generic Order No. 25 at 1. The scope of our review of the August 2000 order on use of the generic

escalators will not include evidence or testimony from the Reliant-specific proceeding that was

admitted after the August 2000 order.17

Reliant points to the testimony of James Brian to support its claim that the generic

escalator would be ineffective to compensate for increased vegetation control. Brian argued against

the use of generic escalators. He argued that, even if generic escalators are used, utilities should be

allowed to show that the generic escalators would not account for some major expenses because

either the expenses did not exist in the test year or would increase from the test year at a rate that

exceeded the escalator rate. Brian testified that Reliant’s tree-trimming expenses would increase

$11.6 million to comply with heightened reliability standards, but he did not provide a context for

that increase—i.e., show what percentage increase that would be.18 He calculated that Reliant’s

actual expenses for 2002 would outstrip the expenses estimated by using a single generic escalator

(an approach not adopted by the Commission) by more than $67.7 million overall: $393.9 million

actual expenses compared to $326.2 million escalated expenses.

Defenders of the generic escalators cite evidence showing that generic escalators can

account for variances in the actual rate of increase of expenses that existed during the test year.

Steven Andersen testified that productivity increases could offset some increased expenses, and

17
This determination excludes from our review testimony in the Reliant-specific proceeding
from witnesses such as Georgianna Nichols, Alan Ahrens, and Reginald Comfort. We note further
that the testimony of Nichols and Comfort was admitted by the ALJ in the Reliant-specific
proceeding as an offer of proof only, and that we have not been asked to review the correctness of
the exclusion of that evidence.
18
Evidence of the tree-trimming expenses was contained in the evidence from the Reliant-
specific proceeding but, as discussed, such evidence is outside the scope of our review.

40
cautioned against making exceptions to the escalator for specific expenses. He posited that increased

tree trimming could result in fewer power outages, thus decreasing outage-related expenses.

Defenders of the generic escalators argue that Reliant increased its tree-trimming expenses in

anticipation of the new reliability rules, but they rely on evidence from the Reliant-specific

proceeding. Commission employee Brian Almon testified that demand-side management expenses

and transmission access charges should be excluded from the generic escalator because both were

modified by statutes effective after the end of the 1999 test year and would have a “significant

impact on the expenses of the utilities.”

Reliant argues that the Commission’s failure to exclude the increased vegetation-

control costs from application of the generic escalator is arbitrary and capricious because it fails to

consider the utility’s actual operating expenses and thereby fails to allow Reliant to recover those

expenses. Reliant dismisses the explanation that the escalator accounts for some costs being

overrecovered and others being underrecovered, noting that the Commission excluded demand-side

management expenses, transmission access charges, and corporate restructuring costs—the first two

of which, at least, also were among Reliant’s expenses before unbundling. Reliant contends that the

Commission acted arbitrarily and capriciously by excluding those expenses, but not the vastly

increased vegetation control expenses.

We conclude that the record supports the Commission’s use of generic escalators.

There was evidence that generic escalators could account generally for TDUs’ increased expenses.

There was evidence that increased expense of one type that exceeded the escalator rate could

nevertheless be balanced by increases in productivity or decreases in other types of related expense.

41
We are cited to no evidence from the generic proceeding supporting Reliant’s argument that the

Commission acted arbitrarily and capriciously by applying the escalator to tree-trimming costs, but

excluding demand-side management expenses. The Commission is the sole judge of the weight to

be accorded the testimony of each witness. CPL, 36 S.W.3d at 561. The agency may accept or reject

the testimony of witnesses or may accept part of a witness’s testimony and disregard the remainder.

Id. Therefore, the agency was free to accept its staff witness’s testimony regarding what expenses

should be exempted from the generic escalation factor and reject Reliant’s witness’s testimony

regarding its increased tree-trimming costs and the necessity that those expenses be exempted from

the generic escalation factor. Substantial evidence supports the Commission’s order. We overrule

Reliant’s third issue.

NEIL Surplus

Gulf Coast complains that the Commission erred by rejecting the ALJ’s

recommendation and failing to reduce the Reliant TDU’s rates based on its share of surplus funds

from the Nuclear Electric Insurance Limited (“NEIL”) funds. In the order, the Commission

describes NEIL as “a mutual enterprise founded, controlled, and operated by utilities owning nuclear

generating capacity that insures against losses related to nuclear generation plants.” See Reliant

Order at 59. The Commission went on to write the following:

In a typical year, NEIL pays out a portion of its underwriting and investment income
in the form of distributions to its members. These distributions are essentially rebates
against the prior year’s premiums. The amount that is not paid out to members as
distributions accrues as surplus and is retained by NEIL. NEIL is required to have
a reserve in the amount necessary to cover two full policy limit losses in one year.
At the end of 1999, the NEIL surplus stood at a total of $4.1 billion. While the

42
surplus is not actually paid out to the members, NEIL tracks each member’s share,
which is known as the member account balance (‘MAB’). Reliant’s MAB at the end
of 1999 was $4,850,718.

Id. The ALJ recommended that the Commission require Reliant to calculate its MAB at the end of

2001, establish a regulatory asset that remains with the TDU, and use those amounts to moderate

rates in future transmission and distribution rate proceedings regardless of whether NEIL distributes

the MAB to Reliant. Although Reliant did not file an exception to the recommendation, the

Commission reversed the ALJ. The Commission opted to keep the NEIL assets with the generation

company because they are primarily generation-related, and use them to increase the value of the

generation plant and reduce stranded costs at the 2004 true-up proceeding. Id. at 60.

Gulf Coast complains that the Commission should have followed the ALJ’s proposal

to credit ratepayers with Reliant’s MAB because Reliant’s NEIL premiums have been paid for and

supported by ratepayer-derived funds. Gulf Coast argues that NEIL assets are not transferrable, are

not an asset affiliated with the generation plant, and will not be accounted for in the true-up. Gulf

Coast contends that the Commission’s contrary decision is without support in the record.

The record provides support for the Commission’s decision. There was conflicting

testimony. Gulf Coast’s witness, Michael Arndt, testified that Reliant’s MAB should be credited

to ratepayers because Reliant’s NEIL premiums have been paid for and supported by ratepayer-

derived funds. Arndt testified that ratepayers should benefit from the surplus accrued before

generation became unregulated. Therefore, he recommended that Reliant’s share of the surplus be

amortized over a short period and returned to ratepayers through transmission and distribution rates.

43
He opined that, if NEIL would not release the funds, Reliant’s generation company should provide

the funds. Reliant witness Brian testified that the surplus did not actually belong to the constituent

companies except as they remained members until the dissolution of NEIL. Brian explained that,

after unbundling, whatever interest Reliant had in the MAB would be owned by Texas GENCO,

Reliant’s generation company, not Reliant’s TDU. He also testified that ratepayers had benefitted

from rates attributable to the premiums because the utility had been insured. But ratepayers of the

TDU would be relieved of those costs in rates. Further, were there any NEIL benefit to Reliant in

excess of risk coverage, that benefit would show up in the stock valuation that would be used to

determine the Reliant generation company’s actual stranded costs under PURA. Therefore,

ratepayers still had a chance to reap a benefit from the MAB.

In its order, the Commission stated that it agreed with Reliant that ratepayers have

received benefits from the NEIL premiums through reduction of financial risk from catastrophic

losses at the nuclear plant. Ratepayers have also received credits for these rate expenses through

NEIL distributions. The Commission stated that the value of the MAB will be taken into account

when the generation plant is valued and accounted for in the 2004 true-up proceeding for stranded

costs; the Commission stated that the benefits from NEIL insurance should increase the value of the

nuclear plant, thereby decreasing any stranded costs. Therefore, the Commission determined that

NEIL MAB assets should remain with the generation company. Although reasonable minds could

differ, the Commission’s decision is reasoned and supported by substantial evidence in the record.

Gulf Coast’s fourth issue is overruled.

44
RATE DESIGN

OPC challenges three elements of the rate design. OPC complains about the

transmission cost recovery factor, a rate design feature that allows TDUs to pass through to retail

electric providers any changes to wholesale transmission rates that TDUs charge retail electric

providers as billing agents for all interconnected wholesale transmission providers in Texas. OPC

also complains that the Commission included an amount in rates for a minimum cost necessary to

distribute some electricity to each customer. OPC also challenges the rate of escalation for coal fuel

cost estimates and the rate of reduction of the estimated capacity of generators.

Transmission Cost Recovery Factor

OPC argues by its first point of error that the Commission exceeded its authority in

approving a transmission cost recovery factor (“TCRF”) containing an automatic flow-through

mechanism. OPC contends that, although the Commission may authorize an electric utility to pass

along wholesale rate increases automatically, the Commission’s approval of the TCRF instead allows

the automatic adjustment of retail rates. OPC further challenges the implementation of the TCRF

because it is inconsistent with the rate freeze instituted during the transition to deregulation. Last,

OPC argues that the TCRF is bad policy.

Although the Commission cannot authorize an electric utility to pass through changes

in fuel or other costs automatically (see PURA § 36.201), the Commission may provide for periodic

adjustment of wholesale rates “to ensure timely recovery of transmission investment.” See id.

§ 35.004(d). The Commission may even approve “a change in wholesale transmission service rates

during the freeze period.” See id. § 39.052(h).

45
The TCRF is a means to allow a distribution service provider (DSP) to adjust the rate

it charges retail electric providers to account for changes in the transmission costs of the electricity

it distributes to the retail electric providers. See 16 Tex. Admin. Code § 25.193(b). Consistent with

the Commission’s authority to permit periodic adjustments of wholesale rates to account for changes

in transmission rates (see PURA § 35.004(d)), the administrative code permits a transmission service

provider (TSP) to “periodically revise its transmission service rates to reflect changes in the cost of

providing such services” subject to the Commission’s filing requirements. See 16 Tex. Admin. Code

§ 25.192(g). “A TSP’s transmission rate shall remain in effect until the commission approves a new

rate.” See id. § 25.192(b)(1). The Commission rules allow a DSP

to include within its tariff a TCRF clause which authorizes the distribution service
provider to charge or credit its customer for the cost of wholesale transmission cost
changes approved or allowed by the commission service to the extent that such costs
vary from the transmission service cost utilized to fix the rates of the distribution
provider.”

See id. § 25.193(b).

OPC argues that the TCRF is an impermissible automatic pass-through of

transmission costs to retail customers, but the TCRF does not apply to retail sales. OPC’s argument

that changes in the TCRF directly affect the retail price of electricity does not overcome the fact that

the TCRF expressly applies only to the transaction between the DSP and the retail electric provider,

which is not a retail transaction.

More important to the protection of retail customers, the adjustment of the

transmission rates is not entirely automatic. While the TCRF is formulaic, it is derived from

46
transmission rates that are approved by the Commission. See 16 Tex. Admin. Code §§ 25.192-.193

(2004). There are procedural prerequisites to the pass-along. The DSP must have a TCRF rate

increase clause in its tariff. See id. The DSP’s rate increase is also subject to a Commission-

approved formula. See id. § 25.193(c). The formula consists of many variables, one of which is the

“new wholesale transmission rate approved by the commission by order or pursuant to commission

rules.” See id. The Commission’s formula appears within the statutory authorization to facilitate

wholesale rate increases to “ensure the timely recovery of transmission investment.” PURA

§ 35.004(d) (emphasis added).

The record indicates that the Commission considered alternatives to the TCRF. It

discussed options presented by Commission staff. See Reliant Order at 37-38. It noted the

testimony of City of Houston witness Daniel, who contended the TCRF violated PURA because

transmission costs were not specifically mentioned as an exception to the rule prohibiting the

automatic pass through of a utility’s costs. Id. The Commission’s decision to follow its staff’s

recommendations is within its discretion. Despite OPC’s argument that the Commission’s decision

is bad policy, we may reverse the agency’s decision only if the decision is “not reasonably supported

by substantial evidence.” See Tex. Gov’t Code Ann. § 2001.174(2)(E). An agency’s decision is

supported by substantial evidence if it is reasonable or rational. See City of El Paso v. Public Util.

Comm’n, 883 S.W.2d 179, 185 (Tex. 1994). The Commission was authorized to adopt the TCRF

to adjust wholesale rates to ensure the timely recovery of transmission investments, and it did so in

a reasoned manner. We overrule OPC’s first point of error.

47
Reliant’s Minimum Plant Methodology

In point of error four, OPC argues that the Commission erred by rejecting the ALJ’s

recommendation and adopting Reliant’s methodology for calculating its “minimum plant”—the

investment needed to connect customers and provide for minimum usage—as part of its allocation

of costs of service. The ALJ recommended that the Commission reject Reliant’s minimum plant

classification of poles, towers, overhead lines, and transformers. OPC complains that the

Commission rejected the ALJ’s recommendation and adopted Reliant’s calculations even though

Reliant failed to file an exception to the ALJ’s recommendation and otherwise failed to explain what

OPC describes as statistical and logical problems in the analysis underlying Reliant’s calculations.

OPC asserts that the Commission did so impermissibly without explanation or support in the record.

The Commission can change, modify or vacate an ALJ’s order when the Commission

determines that the ALJ misapplied or misinterpreted Commission rules or policies, applicable law

or prior administrative decisions, or issued a finding of fact not supported by a preponderance of the

evidence. See Tex. Gov’t Code Ann. §§ 2001.058(e)(1), 2003.049(g). The Commission must “state

in writing the specific reason and legal basis for its determination” to depart from the ALJ’s order.

See id. § 2003.049(h).

In its order, the Commission noted that the ALJ rejected Reliant’s minimum-plant

methodology “because no other utility had employed it, and because the underlying plant study was

‘questionable.’” Reliant Order at 63. The Commission explained its rejection of the methodology

as follows:

48
The Commission notes, however, that P.U.C. Subst. R. 25.344(h)(2)(B) requires that
costs be allocated based on the methodology used in the utility’s last cost of service
study unless determined otherwise by the Commission. Reliant used the minimum
plant methodology in Docket No. 12065. Therefore, the Commission finds that the
use of minimum plant methodology is appropriate.

Id. In its brief, the Commission points to evidence that supports its rejection of the ALJ’s

recommendation. The Commission points to evidence from Reliant’s witness James Purdue that

some costs should be allocated to consumers because those costs are specific to the provision of

power to consumers irrespective of the amount of their usage. He testified that those costs included

distribution equipment such as poles, conductors, and transformers. He noted that these costs were

calculated in Reliant’s application. TIEC witness Jeffry Pollock agreed with Purdue. He stated that,

although some portion of the distribution network costs could fairly be allocated based on usage or

demand because increased demand would require more capacity, that portion of the basic

infrastructure needed to supply power should be allocated to customers. He opined that assessing

14% of the net distribution plant costs as customer-related was not excessive, and flatly rejected the

assertion by OPC witness Clarence Johnson that all of the distribution network costs should be

allocated as demand-related rather than customer-related.

In its reply brief, OPC does not challenge the Commission’s assertion that Purdue’s

evidence provides substantial evidence on which the Commission’s could decide to reject the ALJ’s

recommendation, but insists that the Commission’s explanation in its opinion for rejecting the ALJ’s

recommendation is inadequate.

The Commission plainly rejected the ALJ’s recommendation because it was

inconsistent with the Commission’s previous ruling approving Reliant’s minimum plant

49
methodology. Although the Commission (and the ALJ) could depart from the previous ruling if

there was reason to depart from the previous methodology, the record contains substantial evidence

to support the Commission’s decision that no such reason existed. Accordingly, we affirm the

Commission’s rejection of the ALJ’s recommendation. We overrule OPC’s fourth point of error.

3% Escalation Rate

In point of error five, OPC argues that the Commission erred in applying a 3%

escalation rate to the price of coal for the years 2010 through 2026. OPC complains that the ALJ did

not provide support for the finding that Powder River Basin coal is in significantly higher demand

than coal from other regions and will escalate in price more rapidly than other coal. OPC complains

that no evidence supported either the Commission’s use of 3% as the escalation rate or its change

of the start date for the rate escalation to 2010 from the ALJ’s recommended 2011.

In the February 7, 2001 PFD, the ALJ recommended a 3% escalation rate. The ALJ’s

finding was supported by Reliant witness Janie Mitcham, who testified that the popularity of low-

sulfur coal from the Powder River Basin used by Reliant would likely increase regardless of overall

coal demand, and that transportation bottlenecks would nevertheless limit the accessible supply. She

attached to her testimony an excerpt from the Coal News, which predicted a 3%-5% increase in the

cost of Powder River Basin coal. Several witnesses, including Randall Falkenberg, challenged

Mitcham’s methodology, arguing for lesser escalation. Commission staff witness Jay Curtis testified

that a 3% escalation rate was “appropriate because it is consistent with general price forecasts and

is generally consistent with the escalation Reliant used for coal prices for the 2000-2009 period and

for lignite prices for the post-2009 period.”

50
OPC’s assertion that the Commission changed the ALJ’s recommendation for the

start date is mistaken. In Finding of Fact No. 20 of the PFD, the ALJ recommended that the 3%

annual escalation begin in 2010. The record indicates that Reliant’s fuel contracts expire in 2009,

thus making the year 2010 the logical year in which to begin applying a forecasted rate. The

Commission adopted the ALJ’s recommendation that the escalation begin in 2010.

Rather than changing the ALJ’s PFD, the Commission adopted the ALJ’s decision,

which was supported by substantial evidence. We overrule OPC’s fifth point of error.

0.5% Reduction in the South Texas Nuclear Power Plant and Coal Plant Capacity Factors

In points of error six and seven, OPC asserts that no evidence supports the ALJ’s

decisions to adopt a 0.5% annual reduction in the capacity factor19 for Reliant’s nuclear and coal

power plant. In point of error six, OPC contends that no party requested that the Commission begin

applying the reduction factor beginning in 2010 instead of 2011 as the ALJ proposed.

The ALJ’s decision to adopt a reduction factor for both the nuclear power plant and

the coal powered plants has evidentiary support. Reliant witness William G. Rice testified that

Reliant’s “older units” would begin to experience some degradation in their performance capability

beginning in 2011. He estimated that the decline for coal and nuclear plants would be 1% annually.

Reliant witness Ernie McWilliams agreed with Rice that degradation would occur due to increasing

rates of random component failures. He asserted that the prime productive period of a generator

19
The ALJ defined capacity factor as “the percentage of time that a plant (1) is available to
run (i.e., is not undergoing a planned outage or forced outage); and (2) would be anticipated to run
under economic dispatch principles.”

51
ranges between 10 and 40 years. Rice testified that the relevant generators would be between 20 and

25 years old in 2011. Rice and McWilliams disagreed with OPC’s Falkenberg and the City of

Houston’s Scott Norwood, who asserted that maintenance and advanced technology could offset any

normal degradation in the capacity of power plants. There is substantial evidence for the adoption

of a reduction rate.

The Commission’s decision to set the reduction rate at 0.5% is also supported by

substantial evidence. OPC asserts that no witness advocated a 0.5% reduction rate. That is strictly

correct. But some witnesses’ testimony supported a 1% reduction rate, which by definition

encompasses the 0.5% rate adopted. The contrary evidence that degradation was avertable did not

require a choice of between 0% or 1%; rather, the evidence that degradation would occur but was

possibly avoidable supports the choice of any figure in that range. See City of El Paso, 883 S.W.2d

at 186. Substantial evidence supports the Commission’s adoption of the ALJ’s proposed 0.5%

degradation rate.

The Commission’s decision to change the beginning date for applying the degradation

rate to the nuclear generator was consistent with evidence in the record and with a prior decision by

the Commission. The Commission may depart from an ALJ’s recommendation if it does not

properly apply previous Commission decisions. See Tex. Gov’t Code Ann. §§ 2001.058(e)(1),

2003.049(g). The ALJ recommended applying the degradation rate beginning in 2011. Despite the

fact that this start date was derived from Reliant witnesses, Reliant excepted to the ALJ’s proposal

because the 2011 start date differed from the 2010 start date that the Commission used for the same

degradation rate for the same generator in another proceeding. See Tex. Pub. Util. Comm’n,

52
Application of Cent. Power and Light Co. for Approval of Unbundled Cost of Service Rate Pursuant

to PURA § 39.201 and Pub. Util. Comm’n Substantive R. § 25.344, Docket No. 22352 at 112, 2001

Tex. PUC LEXIS 110, at *205 (Oct. 2, 2001). In its order in this case dated the next day, October

3, 2001, the Commission agreed with Reliant’s exception and noted that, for the sake of consistency,

the 0.5% reduction factor should begin in 2010 as it did in the CPL case, not in 2011 as the ALJ

recommended in this case. See Reliant Order at 54-55. The change is permissible because it is

supported by substantial evidence and brings the decision in this case into line with a prior agency

decision. We overrule OPC’s points of error six and seven.

CONCLUSION

We conclude that the district court correctly affirmed the Commission’s order except

as it concerns the costs of interconnecting Merchant Plant 4. We reverse that finding and related

conclusions and remand to the Commission for further proceedings based on the existing

administrative record.

David Puryear, Justice

Before Justices B. A. Smith, Patterson and Puryear

Affirmed in Part; Reversed and Remanded in Part

Filed: December 16, 2004

53

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Source: Frix Law Library, https://www.frixlaw.com/law-library/cases/2867551. Public record. Not legal advice.