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
TEXAS COURT OF APPEALS, THIRD DISTRICT, AT AUSTIN
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
Several parties appeal from the district court=s judgment affirming a final order of the Public
Utility Commission (Athe Commission@) setting cost-of-service rates for the transmission and distribution
utility (ATDU@) of Reliant Energy, Inc. (AReliant@).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
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 AHouston
Lighting and Power@ or AHLP,@ we will refer to the company as AReliant.@
the Commission=s findings of fact was a prohibited advisory opinion, but otherwise affirmed the
Commission=s order. Reliant, Gulf Coast Coalition of Cities (AGulf Coast@), Office of Public Utility Counsel
(AOPC@), and Consumer Owned Power Systems 2 (ACOPS@) 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.CAustin 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.CAustin 2001, no pet.). Under the regulated system, a single utility generated electricity, built 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 (APURA@),3 finding that the Apublic interest in
competitive electric markets requires that, except for transmission and distribution services and for the
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 AConsumer Owned
Power Systems.@
3
Tex. Util. Code Ann. '' 11.001-64.158 (West 1998 & Supp. 2004) (hereinafter APURA@).
2
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 unbundled TDUs did
4
This Court has discussed the components of the Arate base@:
The term Ainvested capital@ is not made the subject of a specific definition in PURA
although the term is said to be synonymous with the term Arate base,@ see 16 Tex.
Admin. Code ' 25.231(c)(2) (2003); and, the Acomponents@ of invested capital are
3
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
Aestablish 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 Aoriginal cost, less depreciation, of property used
described broadly as Aproperty 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 Acosts of facilities, revenues, expenses, taxes, and reserves@ in arriving at rates
that were just and reasonable. Id. ' 36.055.
American Elec. Power Co. v. Public Util. Comm=n, 123 S.W.3d 33, 35 (Tex. App.CAustin 2003, no
pet.).
4
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 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,
AReliant Order@).
5
Stranded costs are Athe 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.CAustin 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.CAustin 2000, pet. denied) (ACPL@). 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
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 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;
6
(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.CAustin 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 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.
ASubstantial 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.CAustin 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
7
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 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
Aused by and useful to the utility in providing service.@ See PURA '' 36.051, .053(a);6 see also 16 Tex.
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:
8
Admin. Code ' 25.231(c)(2) (2003). A>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 (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.CAustin 1995, writ dism=d). As the United
States Supreme Court has written, AThe 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
(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 Aoriginal cost@ means the actual money cost or the actual
money value of consideration paid other than money.
(Emphases added.)
9
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.
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
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.
10
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 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 Aused 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
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). AWe might accurately compare the circumstances in 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.CAustin
1992), rev=d on other grounds, 901 S.W.2d 401 (Tex. 1995).
11
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
(Ayear-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 (Aaverage-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
Aused and useful@ in providing service. PURA '' 36.051, .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 Afar 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.
12
See generally Central Power & Light Co. v. Public Util. Comm=n, 36 S.W.3d 547, 552-53 (Tex.
App.CAustin 2000, pet. denied) (ACPL@). 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 Aused and useful@ in supplying
electricity.
The City of Houston, Texas Industrial Energy Consumers (ATIEC@), and OPC sponsored
witnesses who supported using the average-year method. Houston=s James Daniel 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 Aused 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, 2002Calmost 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,
13
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 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, AAll 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
14
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, AIt 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 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 Aused 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
15
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 evidence. See
Tex. Gov=t Code Ann. '' 2001.058(e)(1), 2003.049(g) (West 2000). The Commission must Astate 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. AAn 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 Aused and useful@ enough to be included in
16
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 yearsCparticularly 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 effectCessentially creating an average-
two-year methodCis not erroneous.
We overrule Gulf Coast=s third issue, OPC=s second issue, and all of COPS=s issues.
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
17
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 $107.3 million, but then listed that amount under the column heading A$
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 allows Reliant to increase the capacity of existing transmission 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
9
Although the quoted passage may be ambiguous in isolation regarding which Aproject@ is
estimated to cost $50.2 million, the context shows that the relevant project is the Merchant Plant 4
18
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 (APFD@) 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, ANobody 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 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
for the cost of the Merchant Plant 4 interconnection. This is the amount Houston originally estimated the
interconnection of Merchant 4 plant would cost and ignores his revised estimate.
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.
19
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.CAustin
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 expertCeven 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.C 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 contends that Houston=s
original testimony is the only source of the $107.3 million estimate, and that his revised estimateCthe validity
of which is unchallengedCrenders the original estimate essentially a nullity. Gulf Coast contends that the
ALJ used the $107.3 million estimate only because it adopted 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.
The record in this case does not show that the Commission rejected Houston=s revised
testimony. Rather, there is no indication that the commissioners were reminded of the rebuttal testimony
when they revised the PFD to include $107.3 million for Merchant Plant 4. The record of the hearing at
20
which the Commission decided to include Merchant Plant 4 costs reveals that, when the commissioners
requested that staff find out how much the Merchant Plant 4 interconnection would cost, staff reported the
cost as $107.3 million. 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 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. Nothing in the record rebuts his
assertion that Reliant would not build the new transmission line. Although deference is due the agency=s
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.
21
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. It appears from the
record that the Commission=s use of Reliant=s original cost projection was inadvertent and not based on
substantial evidence.
In light of Houston=s uncontroverted downward revision of his estimate, no reasonable basis
existed to use the original estimate. 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.CAustin 1979, no writ); First Sav. & Loan Assoc. v. Lewis, 512 S.W.2d 62, 64
(Tex. Civ. App.CAustin 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
22
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.
PURA requires that the Commission set a Areasonable@ return on the utility=s invested
capital. PURA ' 36.051. In setting this return, the Commission Ashall 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 Aultimate@ findings on each issue. See Meier Infiniti Co. v.
Motor Vehicle Bd., 918 S.W.2d 95, 100 (Tex. App.CAustin 1996, writ denied). A[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
TDUsCincluding the level of regulatory oversight and comparable levels of riskCand concluded that a
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
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 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 Athe 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.
24
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. 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 Aissues@ 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 Aproceedings@ 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.CAustin 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.CAustin 1997, no pet.). In El Paso, we wrote, AAny 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:
25
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.
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 historyCnone. 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
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
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 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 Awill 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
testimonyCparticularly 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.
27
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.
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.CAustin 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.CAustin 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
28
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 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
conflictCi.e., PURA section 36.052 does not prevent unbundlingCthe 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
29
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.CAustin 1998, pet denied); City of El
Paso v. Public Util. Comm=n, 609 S.W.2d 574, 578 (Tex. Civ. App.CAustin 1980, writ ref=d 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 Aeconomic 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
30
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 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
31
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 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 Areasonable 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 Afair 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.
32
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 periodCyears in which the Commission had already apportioned fair shares of the tax
savings. Utility rates are set prospectively, and the Commission Amay 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[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
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
lossesClosses that would have had no value to the parent during the fifteen-year period if one of its affiliates
33
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 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.
had not earned profits against which those losses could be appliedCwere 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.
34
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.CAustin 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 Ais plainly erroneous or
inconsistent with the regulation.@ Id. at 207.
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
Agrossed-up@ that figure to $29 million. Reliant complains that the Commission failed to distinguish between
14
Reliant explains in its appellant=s brief that the gross-up factor is an adjustment made to negate
the effect of taxes: AFor 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
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. GTE-Southwest, Inc., 833
S.W.2d 153, 159 (Tex. App.CAustin 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
36
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.
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
15
No party challenges Reliant=s assertion that the gross-up factor was not used in CPL; the term
Agross-up@ does not appear in our CPL opinion. See generally, 36 S.W.3d at 547-72.
37
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 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
38
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 Anew@ 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 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.
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
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.
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
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.
40
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 increaseCi.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 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
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.
41
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 Asignificant 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 costsCthe 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. 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
42
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 (ANEIL@) funds. In the order, the Commission describes NEIL as Aa 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 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.
43
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. 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
44
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.
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.
45
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 (ATCRF@) 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 Ato ensure timely recovery of transmission investment.@ See id. ' 35.004(d). The
Commission may even approve Aa change in wholesale transmission service rates during the freeze period.@
See id. ' 39.052(h).
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 Aperiodically revise its transmission service rates to reflect changes in the cost of providing such
46
services@ subject to the Commission=s filing requirements. See 16 Tex. Admin. Code ' 25.192(g). AA
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 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 Anew wholesale transmission rate approved by the
commission by order or pursuant to commission rules.@ See id. The Commission=s formula appears within
47
the statutory authorization to facilitate wholesale rate increases to Aensure 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 onlyif
the decision is Anot 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.
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 Aminimum plant@Cthe investment
needed to connect customers and provide for minimum usageCas 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
48
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 Astate 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 Abecause 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:
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
49
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 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
50
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 Aappropriate
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.@
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.
51
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 Aolder
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 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
19
The ALJ defined capacity factor as Athe 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.@
52
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, 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
53
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: August 26, 2004
54