Jonah Water Special Utility District v. Aaron Keith White and Lance White ( 2009 )

TEXAS COURT OF APPEALS, THIRD DISTRICT, AT AUSTIN
NO. 03-05-00644-CV
Appellant, AEP Texas North Company// Cross-Appellants, Cities of Abilene, Ballinger,
San Angelo and Vernon
v.
Appellees, Public Utility Commission of Texas, Office of Public Utility Counsel, Texas
Industrial Energy Consumers, Cities of Abilene, Ballinger, San Angelo and Vernon//
Cross Appellee, AEP Texas North Company
FROM THE DISTRICT COURT OF TRAVIS COUNTY, 98TH JUDICIAL DISTRICT
NO. GN404175, HONORABLE STEPHEN YELENOSKY, JUDGE PRESIDING
OPINION
On June 3, 2002, West Texas Utilities Company (“WTU”),1 a subsidiary of American
Electric Power Company, Inc. (“AEP”), filed a petition with the Public Utility Commission of Texas
(the “Commission”) for reconciliation of its eligible fuel expenses and revenues for the period from
July 1, 2000, to December 31, 2001. This represented WTU’s final fuel reconciliation as an
integrated utility. The cities of Abilene, Ballinger, San Angelo, and Vernon (“Cities”), Texas
Industrial Energy Consumers, and the Office of Public Utility Counsel (“OPC”) intervened and
recommended various disallowances to TNC’s petition. After hearings, the Commission issued its
1
Effective December 23, 2002, the legal name of WTU changed to AEP Texas North
Company (“TNC”).
order on rehearing, the final order in this case. TNC and the Cities appealed the Commission’s
decision to the Travis County District Court, which affirmed the final order in all aspects. This
appeal followed.
TNC argues that the Commission erred by (1) extending the reconciliation period;
(2) not following prior reconciliation methodology; (3) improperly sharing TNC’s off-system sales
margins with its ratepayers; and (4) denying TNC’s request to include the settlement payments made
in a prior docket as part of its final fuel reconciliation. Cities bring four issues on appeal,
complaining that the Commission erred by (1) finding that TNC’s spot gas purchases were prudent;
(2) applying an inappropriate standard of review in evaluating TNC’s natural gas costs;
(3) determining that the Oklaunion coal-fired plant operated efficiently and productively in 2001;
and (4) finding that a maintenance outage at the Oklaunion plant was prudent.
For the reasons set forth below, we affirm the district court’s judgment.
FACTUAL AND PROCEDURAL BACKGROUND
Through the Public Utility Regulatory Act (“PURA”), the legislature empowered the
Commission to regulate electric utilities. See Tex. Util. Code Ann. §§ 11.001-66.016 (West 2007
& Supp. 2008). Prior to January 1, 2002, each electric utility in a designated service area operated
as a monopoly with regulated rates. Office of Pub. Util. Counsel v. Public Util. Comm’n of Tex.,
104 S.W.3d 225, 227-28 (Tex. App.—Austin 2003, no pet.).
The Commission set rates for the utilities that allowed them to recover their prudently
incurred costs and to receive a reasonable return on their investments. AEP Tex. Cent. Co. v. Public
Util. Comm’n of Tex., No. 13-06-00311-CV, 2008 Tex. App. LEXIS 9541, at *3-4
2
(Tex. App.—Corpus Christi Dec. 22, 2008, pet. filed). However, because the cost of fuel often
changes and because the Commission cannot hold rate proceedings every time it changes, PURA
applies a “fuel factor.” See 16 Tex. Admin. Code § 25.237 (2009). “Fuel factors are calculated by
dividing the electric utility’s projected net eligible fuel expenses by the corresponding projected
kilowatt-hour sales for the period in which the fuel factors are expected to be in effect.” Office of
Pub. Util. Counsel v. Public Util. Commn’n of Tex., 185 S.W.3d 555, 561-62 (Tex. App.—Austin
2006, pet. denied). In other words, PURA allowed the electric utilities to charge rates that included
the recovery of fuel costs reasonably expected to be incurred. AEP Tex. Cent. Co., 2008 Tex. App.
LEXIS 9541, at *4; City of El Paso v. El Paso Elec. Co., 851 S.W.2d 896, 898 (Tex. App.—Austin
1993, writ denied). Periodically, through a proceeding before the Commission, the electric utilities
had to reconcile the revenues actually received with the expenses actually incurred. AEP Tex. Cent.
Co., 2008 Tex. App. LEXIS 9541, at *4-5; see PURA § 36.203(e) (West 2007). Depending on the
result of the periodic reconciliation, the Commission either ordered a utility to refund its customers
an over-recovery of fuel costs or permitted the utility to recoup an under-recovery through surcharges
to its customers. City of El Paso, 851 S.W.2d at 898.
In 1999, the legislature deregulated the retail electricity market. See PURA § 39.001
(West 2007). As part of this deregulation, each electric utility was “unbundled,” or split, into
three separate entities: (1) a generation company to generate electricity, (2) a transmission and
distribution company to transmit and distribute electricity to consumers, and (3) a retail electric
provider to buy and resell electricity to Texas consumers. See PURA § 39.051 (West 2007). As part
of the transition to retail electricity competition, the legislature required each generation company
3
affiliated with the former “bundled” utilities to file a final fuel reconciliation application to reconcile
its fuel expenses with the Commission “for the period ending the day before the date customer
choice is introduced.” PURA § 39.202(c) (West 2007). Any over- or under-recovery balance
determined under the final fuel reconciliation is carried over to the “true-up” proceeding, in which
the utility’s “stranded costs,” if any, are determined.2 This case arises from TNC’s final fuel
reconciliation application.
TNC filed its final fuel reconciliation application with the Commission on
June 3, 2002, seeking to recover $23,064,733, plus $3,416,607 in interest, as its under-recovered fuel
balance. The Commission referred the application to the State Office of Administrative Hearings
(SOAH) for a contested-case hearing. After receiving evidence and hearing testimony, the
administrative law judges (ALJs) prepared a proposal for decision (PFD) that recommended, with
some adjustments, approval of TNC’s application.
The Commission considered the PFD and reversed the ALJs’ determinations on the
issues of the duration of the fuel reconciliation period and the AEP companies’ trading activities.
The Commission remanded the case for the taking of additional evidence on the issues of TNC’s
total reconcilable costs and revenues and how TNC should comply with its obligation to share off-
system sales margins with ratepayers for five years, as specified in the Integrated Stipulation and
Agreement in the Commission’s Docket No. 19265.3 An ALJ issued a second PFD, and the
2
“Stranded costs” are capital expenses incurred under a regulatory regime that become
unrecoverable as a result of deregulation. See American Elec. Power Co., Inc. v. Public Util.
Comm’n, 123 S.W.3d 33, 35 (Tex. App.—Austin 2003, no pet.).
3
Application of Central & South West Corporation and American Electric Power Company,
Inc., Regarding Proposed Business Combination, Docket No. 19265 (1999).
4
Commission adopted the supplemental PFD without changes.
The Cities and OPC filed motions for rehearing on the question of including “open
transactions” in TNC’s calculations of off-system sales margins.4 The Commission granted both
motions for rehearing. After finding the record contained insufficient evidence to determine the
dollar impact of its ruling, the Commission remanded the cause to SOAH for additional evidence
on the consequence of excluding open transactions from TNC’s calculations. The parties reached
a stipulated agreement that the Commission adopted in its order on rehearing. TNC and the Cities
appealed the order on rehearing to the district court, which affirmed the Commission’s order in all
respects. This appeal followed.
DISCUSSION
Standards of Review
The parties have raised a variety of issues that we review under different standards
of review. In general, courts review a final order of the Commission under the substantial evidence
rule. See PURA § 15.001 (West 2007); Tex. Gov’t Code Ann. § 2001.174 (West 2008). Although
substantial evidence is more than a mere scintilla, the evidence in the record may actually
preponderate against the Commission’s decision, yet amount to substantial evidence. See Texas
Health Facilities Comm’n v. Charter Med.-Dallas, Inc., 665 S.W.2d 446, 452 (Tex. 1984). When
applying the substantial evidence standard to an agency decision, the test is not whether the
Commission reached the correct conclusion, but whether some reasonable basis for the
Commission’s action exists in the record. Id.; Central Power & Light Co. v. Public Util. Comm’n,
4
“Open transactions” are those in which payment has not yet been received.
5
36 S.W.3d 547, 557 (Tex. App.—Austin 2000, pet. denied).
Under the substantial evidence rule, a reviewing court gives significant deference to
the agency in its field of expertise. Railroad Comm’n v. Torch Operating Co., 912 S.W.2d 790, 792
(Tex. 1995); State v. Public Util. Comm’n of Tex., 246 S.W.3d 324, 331 (Tex. App.—Austin 2008,
pet. filed). We presume that the Commission’s order is supported by substantial evidence, and the
complaining parties, TNC and the Cities, have the burden to overcome this presumption. See City
of El Paso v. Public Util. Comm’n, 883 S.W.2d 179, 185 (Tex. 1994); State v. Public Util. Comm’n
of Tex., 246 S.W.3d at 331-32. We may not substitute our judgment for that of the agency on
matters committed to agency discretion. Tex. Gov’t Code § 2001.174; H. G. Sledge, Inc.
v. Prospective Inv. & Trading Co., Ltd., 36 S.W.3d 597, 602 (Tex. App.—Austin 2000, pet. denied).
We will reverse the agency’s order if substantial rights of the appellant have been prejudiced because
the decision is not reasonably supported by substantial evidence, is arbitrary or capricious, is
characterized by an abuse of discretion, or is a clearly unwarranted exercise of discretion. See
Tex. Gov’t Code § 2001.174(2)(E), (F).
Several issues involve questions of statutory construction, which we review de novo.
When construing a statute, we are to give effect to the legislature’s intent. City of San Antonio
v. City of Boerne, 111 S.W.3d 22, 25 (Tex. 2003). We look to the statute as a whole, as opposed to
isolated provisions, to determine legislative intent. State v. Gonzalez, 82 S.W.3d 322, 327
(Tex. 2002). Where a statutory text is unambiguous, we should adopt a construction supported by
the statute’s plain language, unless that construction would produce an absurd result. Fleming Foods
of Tex., Inc. v. Rylander, 6 S.W.3d 278, 284 (Tex. 1999); State v. Public Util. Comm’n of Tex.,
246 S.W.3d at 332. We give serious consideration to an agency’s interpretation of the statutes it is
6
charged with enforcing, as long as that interpretation is reasonable and consistent with the statutory
language. State v. Public Util. Comm’n of Tex., 246 S.W.3d at 332; Tarrant Appraisal Dist.
v. Moore, 845 S.W.2d 820, 823 (Tex. 1993).
Issues Raised by TNC
The Reconciliation Period
Under section 39.001(b)(1) of PURA, a competitive retail electric market that allows
each retail customer to choose the customer’s provider of electricity was implemented on
January 1, 2002. See PURA § 39.001(b)(1) (West 2007). Each formerly regulated monopoly was
required under section 39.202(c) of PURA to file a final fuel reconciliation “for the period ending
before the date customer choice is introduced.” The “date customer choice is introduced” is
not defined.
In TNC’s final fuel reconciliation, the Commission interpreted “the date customer
choice is introduced’ to mean the actual date when all customers had been switched to either the
affiliated retail electric provider or a competitive retail electric provider. By not specifying
“December 31, 2001,” in PURA section 39.202(c), the Commission argues that the legislature
recognized that a single date for the start of choice for all customers would be impractical and thus
it built into the statute a degree of flexibility. The Commission found that customer choice could
not have been fully “introduced” before the end of the extended reconciliation period and that the
legislature, by using the more ambiguous phrase “the day before customer choice is introduced,”
intended for fuel revenues received and fuel expenses incurred during the transition period after
December 31, 2001, to be included in the final fuel reconciliations. TNC contended that its final fuel
7
reconciliation should only include fuel-related revenues received and expenses incurred up to
December 31, 2001. The Commission, however, ordered that TNC’s final fuel reconciliation should
include the entire period that TNC customers received bundled or rate-regulated service. The
Commission’s determination required TNC to reconcile $15,088,395 in revenues it received in
providing bundled service and $4,276,666 in expenses it incurred during the 2002 transition period.
TNC argues that the statutes mandate that customer choice begin on January 1, 2002,
and that the Commission violated PURA section 39.202(c) by extending the end of the reconciliation
period. Section 39.102(a) of PURA proclaims that each retail customer in Texas “shall have
customer choice on or after January 1, 2002.” PURA § 39.102(a) (West 2007). Moreover, the
legislature in section 39.001(b) of PURA declared it in the public interest to “implement on
January 1, 2002, a competitive retail electric market.” Id. § 39.001(b). Asserting that the word
“introduced” must be construed according to its common usage, TNC claims that the ending date
for its final fuel reconciliation period was December 31, 2001.
The Commission, however, responds that TNC’s argument focuses only on the date
competition was intended to commence and ignores section 31.002(4) of PURA, which defines
“customer choice” as “the freedom of a retail customer to purchase electric services” from a provider
of the customer’s choice. PURA § 31.002(4) (West 2007). For most of TNC’s customers, the
Commission found that customer choice was unavailable on January 1, 2002, and some customers
did not have customer choice until February 1, 2002. Customer choice, therefore, was a freedom that
many of TNC’s customers were unable to exercise on January 1, 2002. TNC claims that customer
choice was available to any TNC customer on January 1, 2002, by switching to a retail electric
provider after requesting a special meter read. However, the record shows that the average customer
8
did not have the option to request a special meter read on January 1, 2002, and, indeed, a significant
majority of those who had requested a transfer to a competitive provider were denied choice until
TNC could read their meters. Additionally, even if all of the customers desired to participate in the
special meter read program, the record contains no evidence that it would have been possible for
every TNC customer to have had a final meter read by midnight on January 1, 2002.
The Commission asserts that its choice of methods to implement the
legislature’s directives is a reasonable interpretation of PURA section 39.202(c) and should be
upheld. We agree. If the legislature had intended in section 39.202(c) that “the day before the date
customer choice is introduced” was to be December 31, 2001, it would have explicitly stated so.
Moreover, TNC fails to recognize that the word “introduce” has more than one meaning; for
example, it can be used to mean “usher in” or “bring in.” The Commission’s interpretation of
“introduced” to mean the actual date when all TNC customers had been switched to either the
affiliated retail electric provider or a competitive retail electric provider is reasonable and consistent
with the statute. That the majority of TNC’s customers could not be transferred to a retail electric
provider until after TNC conducted a final meter read is also persuasive and reinforces the
Commission’s interpretation of the legislative intent behind the choice of words in section 39.202(c).
If customers were unable to connect to a retail electric provider until after the final meter read, then
there was no customer choice until after that time.
Moreover, this was TNC’s final fuel reconciliation, and there would be no further
opportunity for TNC ratepayers to recover those dollars. As the Commission, OPC, Texas Industrial
Energy Consumers, and the Cities all assert, by recovering its fuel expenses without accounting for
the offsetting revenues it collected to recover those costs, TNC would receive a windfall of
9
$10,840,729 to the detriment of its ratepayers who would bear those costs through TNC’s stranded-
cost recovery mechanism.
The Commission’s interpretation “protects the public interest” by ensuring that, in
this final fuel reconciliation, all costs and revenues incurred during the reconciliation period and
associated with bundled services were reconciled. As a sister court has held in a case concerning
AEP Texas Central Company (“TCC”), another AEP subsidiary, we find that the Commission’s
interpretation of the statute is reasonable and does not contradict the plain meaning of the statute.
See AEP Tex. Cent. Co. v. Public Util. Comm’n of Tex., 2008 Tex. App. LEXIS 9541, at *15. See
generally Tarrant Appraisal Dist., 845 S.W.2d at 823; Meno v. Kitchens, 873 S.W.2d 789, 791
(Tex. App.—Austin 1994, writ denied). The Commission’s final order reasonably required TNC
to account for all revenues it collected after December 31, 2001, that were directly attributable to the
generation of electricity through December 31, 2001, and reasonably required TNC to reconcile all
fuel revenues it received and expenses it incurred after December 31, 2001, to serve customers who
were not yet switched to a retail electric provider. TNC’s first issue is overruled.
The Reconciliation Methodology
In its second issue, TNC contends that the Commission violated its own rules by
applying a different fuel reconciliation methodology than that used in prior reconciliations. Under
the Commission’s fuel rule, utilities were required to account for fuel-related revenues collected
“during the reconciliation period.” 16 Tex. Admin. Code § 25.236(d)(1)(C) (2009). The
“reconciliation period” is not defined in the rule.
Instead of reconciling expenses incurred in one month with revenues billed that same
10
month as was done in prior reconciliations, TNC asserts that the Commission in this instance
reconciled expenses with revenues attributable to those expenses but billed in a subsequent month
under the utility’s normal billing cycle. TNC argues this change in the Commission’s methodology
created a “mismatch” between the items reconciled, resulting in a longer time period of revenues
being reconciled than expenses. TNC claims that, because the Commission did not amend its rules,
this change in the Commission’s reconciliation methodology was arbitrary agency action requiring
reversal of the Commission’s final order.
The Commission points out that TNC ceased providing bundled service at the end
of January 2002 and sent out its final bundled-rate5 bills to customers as late as the first billing cycle
in February. Because many of the final payments those customers made were received by TNC in
February 2002, a month with no bundled-rate expenses, TNC’s February balance naturally reflected
only bundled-rate revenues. The Commission asserts that the absence of any fuel-related expenses
did not free TNC from the obligation of including its fuel-related revenues in the final fuel
reconciliation and that TNC’s claim of a mismatch is misleading; contrary to TNS’s argument, the
Commission matched fuel-related revenues and expenses month-to-month as it always had.
We must determine whether the Commission reasonably interpreted its fuel rule and
“the reconciliation period” during which utilities were required to account for fuel-related revenues
that it collected. See 16 Tex. Admin. Code § 25.236; Public Util. Comm’n of Tex. v. Gulf States
Util. Co., 809 S.W.2d 201, 207 (Tex. 1991) (requiring deference to the Commission’s construction
of its own rules, unless its interpretation is plainly erroneous or inconsistent with the rules). Just as
5
A utility’s “bundled” rate refers to the rate charged to customers, including fuel surcharges,
for all service provided by the bundled utility prior to deregulation.
11
we have held that the Commission reasonably interpreted section 39.202(c) of PURA, we also find
that the Commission’s interpretation of its own fuel rule is reasonable.
The Commission recognized not only that the legislature had directed it to conduct
a final fuel reconciliation, but that a normal lag occurs between when an expense is incurred and
when it is billed and collected. In prior reconciliations, costs incurred in the final month of the
reconciliation period and billed in the first months of the next reconciliation period were accounted
for in subsequent reconciliations. Because this was TNC’s final reconciliation, we find that the
Commission reasonably interpreted the legislature’s directive to conduct a final reconciliation by
accounting for all revenues associated with the expenses of providing bundled service during the
reconciliation period. TNC’s second issue is overruled.
Off-System Sales Margins
In addition to requiring reconciliation of expenses and revenues, the
Commission’s fuel rule also required a sharing of profits, called “off-system sales margins,” between
the shareholders and the ratepayers when utilities had excess generating capacity and sold power at
wholesale. 16 Tex. Admin. Code § 25.236(a)(8). Margins were to be shared 10 percent by
shareholders and 90 percent by ratepayers.
When TNC’s former parent, the utility holding company Central and South West
Corporation (“CSW”), merged into AEP, the Commission on May 4, 1999, in Docket No. 19265,
approved an Integrated Stipulation and Agreement (“ISA”), entered into by most of the intervening
parties, which resolved many of the issues involved in regulatory approval of the merger.6 The ISA
6
See Tex. Pub. Util. Comm’n, Application of Central & South West Corporation and
American Electric Power Company, Inc., Regarding Proposed Business Combination,
Docket No. 19265, Order (November 18, 1999).
12
changed the margin-sharing provisions applicable under the fuel rule and provided for the sharing of
off-system sales margins as follows:
G. Off-System Sales Margins
(3) [TNC] off-system sales margins up to $900,000 shall
be credited to customers. For any [TNC] off-system
sales margins between $900,000 to $1.35 million, 85%
of such margins shall be credited to customers and
15% of such margins shall be retained by the
shareholders. For any [TNC] off-system sales margins
above $1.35 million, 50% of such margins shall be
credited to customers and 50% of such margins shall
be retained by the shareholders.
(4) The provisions as to off-system sales margins shall be
in effect for a period of five years from the effective
date of the merger.
* * *
(6) Off-system sales margins to be credited to customers
under this subsection shall be made in the form of
revenue credits in fuel reconciliation proceedings.
Thus, the ISA provided that TNC will share off-system sales margins for five years; it also required
TNC to do so as revenue credits in fuel reconciliation proceedings. Because of deregulation,
however, fuel reconciliation proceedings did not last for five years from the effective date of the
merger on June 15, 2000.
At the initial hearing on this matter, no party contended that the sharing of margins was
to continue beyond the end of fuel reconciliation proceedings. Instead, the issue first arose in OPC’s
post-hearing reply brief and was addressed by the ALJs in the original PFD: “[OPC] found difficulty
perceiving how customers could benefit from more than two years of the agreement’s supposed five-
13
year term, since this reconciliation proceeding is the only mechanism provided for crediting the
relevant margins to customers.” Later, the Cities, discussing TNC’s exceptions to the ALJs’
calculation of a “year” in the original PFD, wrote the following in their reply to exceptions:
There is no possibility that the ALJs’ recommendation
would give “six years of benefit” to customers. AEP
has no intention of honoring the remainder of the
agreement. Customers will not receive near the benefit
contemplated by the Merger Agreement.
Subsequently, when the ALJs’ original PFD was presented at the open meeting, then-
Chairman Rebecca Klein indicated that the ISA had a five-year margin-sharing period, and she saw
an obligation on TNC’s part to make sure that its fuel was reconciled for the outstanding years. She
requested that, when the matter was remanded to SOAH, the parties work out a method in which the
merger obligations could be met for the outstanding years. The Commission thus remanded the
proceedings to SOAH and required the parties to devise a new margin-sharing mechanism so that
TNC could “fulfill its full obligation under the merger agreement.”7
The resulting mechanism used a proxy for the months for which actual margins data
were unavailable. The proxy entailed estimating the total margins that would have been generated
over the unresolved portion of the five-year period, absent deregulation, and crediting that amount
against fuel expenses in this final fuel reconciliation proceeding. Eventually, actual margins
data were used for the first 36 months and the proxy was used for the remaining 24 months of the
five-year period.
7
Order on Remand (May 22, 2003).
14
TNC asserts that the Commission exceeded its authority by extending the statutorily-
limited reconciliation period through 2005 and crediting hypothetical margins to ratepayers in this
final fuel reconciliation. Additionally, TNC contends the Commission violated its due process rights
by excluding evidence that the parties to the ISA intended margin sharing to last only as long as fuel
reconciliation proceedings took place.
Relying on In re Entergy Corp., 142 S.W.3d 316 (Tex. 2004), the Commission
responds that it is not bound by the rules of contract interpretation in construing the ISA and that it
reasonably exercised its authority to enforce its prior order approving the terms of the ISA. The
Commission notes that, in 1998, it opened Docket No. 19265 to review the application of AEP and
CSW for approval of their merger in accordance with PURA, which authorizes the Commission to
investigate proposed mergers and to determine whether the action “is consistent with the public
interest.” See PURA § 14.101(b) (West 2007). The applicants and most of the intervening parties
in Docket No. 19265 agreed to settle various issues relating to the merger, and they became the
signatories to the ISA. Because the settlement was non-unanimous, however, the Commission
determined that it had to make independent findings that the rates proposed by the ISA were just and
reasonable and that those terms were supported by substantial evidence in the record. See Cities of
Abilene v. Public Util. Comm’n, 854 S.W.2d 932, 937 (Tex. App.—Austin 1993), aff’d in part and
rev’d in part, 909 S.W.2d 493 (Tex. 1995). The Commission asserts the ISA assumed the character
of an administrative order, rather than a private contract, because the Commission had to make
independent findings. Consequently, the Commission contends, it was entitled to interpret the ISA
as an agency order and to formulate a reasonable remedy to effectuate the terms of that order.
We agree.
15
In re Entergy Corp. concerned a merger agreement among several parties that became
part of the Commission order approving the merger of Entergy Corporation and Gulf States Utilities
Company. Several ratepayers filed suit and attempted to categorize the merger agreement as a private
contract. However, the supreme court disagreed, noting that, while the agreement may have begun
as a private contract, it took on an administrative character when the parties requested that it be placed
in the Commission order approving the merger.
. . . the Merger Agreement between [the various parties] affected the
public interest and, more importantly, was the basis for the
[Commission’s] approval of the Entergy/GSU merger. Without the
[Commission] order implementing it, the Merger Agreement was
practically meaningless. That is, the very administrative character that
gives the Merger Agreement effect also gives the [Commission] the
authority to adjudicate disputes arising from the agreement.
[Citation removed.]
In re Entergy Corp., 142 S.W.3d at 323-24.
As in In re Entergy Corp., the ISA was more than a private agreement because it
directly affected the public interest. After investigating the proposed merger of AEP and CSW,
including the margin-sharing provisions in the ISA, the Commission found that the agreement’s
provisions with regard to off-system sales were reasonable and in the public interest. Having
determined that, among other things, it was in the public interest that “the provisions as to off-system
sales margins shall be in effect for a period of five years from the effective date of the merger,” the
Commission approved the merger. The Commission’s acceptance of the ISA was necessary to give
the agreement the administrative effect required by the litigants. See id. at 324. The very
administrative character that gave the ISA effect also gave the Commission the authority to adjudicate
16
disputes arising from that agreement and to fashion an administrative remedy that reasonably
accomplished the intended objectives of the Commission’s order. Id.
The ISA clearly stated that the provisions regarding the off-system sales margins shall
be in effect for a period of five years and that the sharing of the margins shall be in the form of
revenue credits in fuel reconciliation proceedings. The Commission accomplished both provisions
of the ISA by finding an alternative mechanism for sharing the remaining 42 months’ worth of
margins of the five-year period in the form of a revenue credit in TNC’s final fuel reconciliation
proceeding.8 The Commission’s interpretation and remedy resulted in all provisions of the margin-
sharing section of the ISA being fulfilled. We find that the Commission’s action was a reasonable
remedy necessary to effectuate the ISA and within the Commission’s statutory authority. See id. at
324 (quoting Public Util. Comm’n v. Southwestern Bell Tel. Co., 960 S.W.2d 116, 119-20
(Tex. App.—Austin 1997, no pet.) (PURA delegates to the Commission the power to formulate and
award a reasonable remedy necessary to effectuate the agreement)); PURA § 14.001 (West 2007).
TNC complains its due process rights were violated because the Commission excluded
David Carpenter’s testimony that explained TNC’s interpretation of the ISA. However, we hold that
the rules of contract interpretation do not apply in construing the ISA and that, while the ISA may
have begun as a private contract, it assumed the character of an administrative order when it became
the basis for the Commission’s approval of the merger between AEP and CSW. See In re Entergy
Corp. at 324. Just as we give great weight to an agency’s interpretation of its own rules and
8
As noted above, actual margins data were used for the first 36 months and a proxy was
used for the remaining 24 months of the five-year period.
17
regulations, we give great weight to an agency’s interpretation of its administrative orders. Cf. In re
Southwestern Bell Tel. Co., L.P., 226 S.W.3d 400, 403 (Tex. 2007); Subaru of Am. v. David McDavid
Nissan, Inc., 84 S.W.3d 212, 221 (Tex. 2002) (courts should defer to an administrative agency when
it is staffed with experts trained in handling complex problems within the agency’s purview and great
benefit is derived from the agency’s uniform interpretation of its statutes and rules); Gulf States
Utilities, 809 S.W.2d at 207 (the Commission’s interpretation of its own rules is entitled to deference
by the courts). Finding that the Commission’s action was within its statutory authority, was neither
arbitrary nor capricious, and did not violate TNC’s due process rights, we overrule TNC’s third issue.
The Load-Forecasting Settlement
To adequately serve the state’s power needs, utilities are required to forecast
“load”—the amount of power that consumers will use during a given time period. A utility company
relies on a variety of information to predict how much power will be used by consumers in different
regions of the state. Prior to August 2001, independent utilities were responsible for forecasting loads
and maintaining the electric power grid. In August 2001, however, the system made the transition
to single-control area operations, that is, the state’s electric load on the grid is now managed by the
Electric Reliability Council of Texas (“ERCOT”). The ERCOT grid is divided into distinct zones,
and different utility entities are responsible for serving loads in distinct zones.
Dividing the grid into distinct zones is important to control the flow of power and to
ensure that the amount of power being consumed is equal to the amount of power being distributed.
In the event load is inaccurately forecasted and too little power is available for a particular zone,
ERCOT pays a premium to a generation resource provider to supply adequate power to that zone.
18
ERCOT then charges a premium to that utility whose load was served.
During August 2001, AEP’s load forecasting was inaccurate in ERCOT’s North and
West Zones. The North Zone over-scheduled its load while the West Zone under-scheduled its load.
TNC was the only AEP Load Serving Entity (“LSE”) serving the North Zone. AEP Service Company
(“AEPSC”), acting as the Qualified Scheduling Entity (“QSE”) on behalf of TNC and its sister
company, TCC, made the inaccurate forecasts. As a result of the inaccurate load forecasting, ERCOT
paid AEPSC approximately $4 million, the market clearing price, for the excess energy in the
North Zone. Likewise, ERCOT charged AEPSC the market clearing price for the shortfall of energy
in the West Zone. Because market clearing prices were significantly higher in the North Zone than
in the West Zone, AEPSC realized new revenues as a result of the error. TNC reflected all gains from
the North Zone in its eligible fuel expenses in August 2001.
AEP discovered the forecasting error and reported it to the Commission. The
Commission investigated the problems in forecasting and found that allocations among the nineteen
QSEs, including AEPSC, were inaccurate. The parties in Commission Docket No. 25755 entered a
settlement agreement, ultimately approved by the Commission in a final order, that led to payments
to and from the various participants to correct inaccurate forecasting.9 Under the terms of the
settlement agreement, AEPSC agreed to pay $3,189,999 to ERCOT for over-scheduling and load
imbalance issues during August 2001. The amount AEPSC agreed to pay was later reduced to
$2,704,246 when AEPSC received credits from other market participants.
9
PUC Investigation into Overscheduling in ERCOT in August 2001, Docket No. 25755,
Order (Nov. 15, 2002).
19
TNC contends that, as a result of the settlement, it repaid $2,704,246 of its
August 2001 fuel revenues. However, the Commission in its final order refused to include the
approximately $2.7 million in TNC’s final fuel reconciliation, finding the following:
57. The Docket No. 25755 settlement agreement provides that
AEPSC and other QSEs are required to remit payments to
ERCOT; however, the agreement does not require [TNC] or
any other ERCOT load-serving entity (LSE) to make
payments.
58. The Docket No. 25755 settlement agreement does not name
[TNC] and does not obligate [TNC] to reimburse AEPSC.
TNC contends the Commission’s order “mistakenly distinguishes” between AEPSC (the QSE) and
TNC (the LSE). According to TNC, this “ignores the undisputable reality” that AEPSC acts as an
arm of TNC in providing QSE services necessary for TNC’s participation in the ERCOT market.
TNC argues that the Commission’s decision to discount approximately $2.7 million
in fuel costs because TNC’s agent rather than TNC made the payments directly is arbitrary and
unsupported by substantial evidence. We disagree. Although TNC presented evidence that AEPSC
was a signatory to the settlement agreement in Docket No. 25755 and agreed to pay approximately
$2.7 million to ERCOT, TNC presented no evidence that it was obligated to reimburse AEPSC for
that payment. Moreover, AEPSC expressly released its parents, subsidiaries, successors, affiliates
(including TNC), and employees from any obligation associated with the approved settlement
agreement.10 We find that a reasonable basis exists for the Commission’s decision to discount
10
Id. at 5.
20
approximately $2.7 million in fuel costs and that the decision is supported by substantial evidence.
See Central Power & Light Co., 36 S.W.3d at 557 (the Commission’s method must be supported by
substantial evidence). TNC’s fourth issue is overruled.
Issues Raised by Cities
TNC’s Natural Gas Purchases
TNC’s overall generation portfolio includes coal, natural gas, the option to burn fuel
oil, and purchased power. During the reconciliation period, natural gas purchases, including the use
of purchased power, accounted for approximately 35 percent of TNC’s total power generation. Gas
spot market prices during the first few months of the reconciliation period were between $4 and
$5 per thousand British thermal units (“MMBtu”). In December 2000, spot prices reached $9 and as
much as $10/MMBtu. TNC paid $9 and $10 for gas throughout January 2001, and the price ranged
between $5 and $6 throughout February 2001. By the last six months of the reconciliation period,
prices had declined to the $2 to $3 range. Cities argue that TNC during this period abandoned the
“portfolio approach,” in which the utility purchases gas under a mix of long-term fixed-price gas
contracts and spot market gas. They proposed a disallowance of $8,437,338.96, claiming that TNC
had purchased 99 percent of its natural gas requirements on the spot market and had no long-term
firm contracts to ameliorate the high gas prices when natural gas prices jumped to $9 and
$10/MMBtu. The Commission, however, rejected Cities’ proposal and found that TNC’s natural gas
purchases were prudent and reconcilable.
Cities assert that the Commission erred in finding that TNC’s natural gas purchases
were prudent and reconcilable. We disagree. To meet its natural gas demands during the
21
reconciliation period, TNC used a combination of purchases: (1) firm and short-term firm
arrangements; (2) monthly spot market purchases; and (3) daily spot market purchases. In order to
take advantage of favorable spot market purchase opportunities, TNC procured its natural gas supplies
on a monthly and daily basis. The record also shows that TNC had firm gas supply arrangements with
terms in excess of a month at a price established pursuant to a predetermined pricing mechanism.
TNC’s longer-term firm arrangements, however, are reflected within the schedules and related
exhibits as spot purchases because the Commission’s fuel reconciliation filing package defined “firm”
as having a term of one year or more.
Over the reconciliation period, TNC’s strategy of purchasing gas on the spot market
resulted in a lower per-unit gas expense than the average investor-owned utility in Texas. The
Commission found that TNC’s average gas cost of $51.37 per megawatt-hour (“MWh”) was below
the $54.94/MWh composite weighted average generation cost for the other Texas investor-owned
utilities. Additionally, TNC’s average gas cost was $4.82/MMBtu compared to the average cost of
$4.91/MMBtu for all other Texas investor-owned utilities. Based on this evidence, the Commission
determined that TNC’s gas purchase strategy during this period was reasonable and prudent. We find
that the Commission’s determination is reasonably supported by substantial evidence and neither
arbitrary, capricious, nor characterized by an abuse of discretion. See Tex. Gov’t Code
§ 2001.174(2)(E), (F). Cities’ first issue is overruled.
Commission’s Standard of Review
Cities allege that the Commission applied the wrong standard of review when
examining TNC’s natural gas purchases. In its preliminary order in this matter issued July 11, 2002,
22
the Commission reiterated that its standard of review for fuel reconciliation is that set forth in its
preliminary order in Docket No. 17460.11 In pertinent part, the standard is as follows:
The Commission has traditionally assessed the prudence of the
utility’s overall operations and management decisions in a fuel
reconciliation docket. Under this standard, a utility’s conduct is
prudent when it involves:
The exercise of that judgment and the choosing of one
of that select range of options which a reasonable
utility manager would exercise or choose in the same
or similar circumstances given the information or
alternatives available at the point in time such
judgment is exercised or option is chosen.
The “judgment” referred to in the standard applies not
only to individual decisions, such as whether to enter
into a particular contract or how a particular contract is
administered, but also to the utility’s judgment in
managing its generation and fuel operations within the
range of reasonable options available at the time the
decision is made.12
The order further states that whether the utility manager has taken into account changes in the market
is an increasingly critical factor in assessing the prudence of management operations.13 Despite this
statement, however, TNC argues the basic standard of review remains the same: whether management
acted reasonably given the information available at the time.
11
Application of Southwestern Electric Power Company for Reconciliation of Fuel Costs,
Surcharge of Fuel Cost Under-Recoveries, and Related Relief, Docket No. 17460, Preliminary Order
(Aug. 22, 1997).
12
Id. at 3-4.
13
Id. at 4.
23
Cities contend the Commission found for TNC solely because its overall natural gas
costs compared favorably with the average cost of other Texas investor-owned utilities. Arguing they
are “unaware of any fuel reconciliation case in which a comparison of utilities’ average gas costs was
used by itself to support a finding of reasonableness,” Cities complain the Commission provided no
notice that it would overturn its well-established practice of not using simple cost comparisons alone
to analyze the prudence of purchases during the reconciliation period. It is arbitrary and capricious
for an agency to adopt and apply a new policy subsequent to the hearing. Flores v. Employees Ret.
Sys. of Tex., 74 S.W.3d 532, 545 (Tex. App.—Austin 2002, pet. denied). Claiming the Commission
applied a standard of review that had never been adopted before, Cities assert the Commission acted
arbitrarily and capriciously in finding that TNC’s gas costs were reasonable based on a comparison
of average prices.
TNC responds there is substantial evidence in the record demonstrating its
management prudence. The Commission’s preliminary order setting forth its standard of review
states that a prudent utility manager “must fully consider the competitive wholesale market and take
advantage of the new opportunities it offers to increase the efficiency of its operations.”14 TNC
contends it obviously exploited the competitive opportunities during the reconciliation period to keep
its fuel cost below that of other investor-owned utilities.
Contrary to Cities’ assertion that the Commission’s decision in favor of TNC was
based solely on a cost comparison, TNC points out the Commission’s final order made findings that
TNC’s purchase strategy was unchanged from that approved in the prior reconciliation; that TNC
14
Id.
24
used a combination of purchases to meet its gas needs; and that TNC’s purchase strategy was
reasonable and prudent.
The Commission points out that, in its preliminary order in Docket No. 17460, it noted
that one of the primary concerns in reconciliation proceedings is “whether the utility’s operational
decisions recognized and exploited the competitive opportunities emerging during the reconciliation
period and whether the utility[‘s] operations produced results similar to those that might have
prevailed in a competitive marketplace.”15 The Commission further stated that it would consider
“how the utility’s costs for fuel and purchased power compared to market rates.”16
Comparing the average unit gas price TNC paid to the price paid by other similar
utilities during the reconciliation period was clearly a comparison of market conditions and satisfies
the standard of review applied by the Commission in its prior fuel reconciliation dockets. The
Commission properly delineated and applied its reasonableness or prudence standard of review set
forth in its preliminary order in Docket No. 17460, which takes into account, among other things,
changes in the market. Finding the Commission acted neither arbitrarily nor capriciously, we overrule
Cities’ second issue.
Oklaunion Coal-Fired Power Plant
Cities complain that the Commission erred by determining that the Oklaunion coal-
fired generating unit operated efficiently and productively during the reconciliation period, thus
incurring reasonable fuel costs. Cities assert that the Oklaunion plant operated at only a 65-percent
15
Id. at 5.
16
Id. at 3.
25
capacity factor, which measures a plant’s actual output as compared to its capability, for two-thirds
of the reconciliation period (2001), the lowest in Oklaunion’s history. Cities claim that, but for a
major turbine overhaul and inspection, Oklaunion would have operated at 80 percent in 2001.
Because of Oklaunion’s lack of productivity in 2001, TNC incurred additional, unnecessary expenses
in the form of high natural gas costs. Cities argue that, had Oklaunion in 2001 achieved a 72-percent
capacity factor such as it achieved while undergoing a planned, major outage in 1995, TNC’s
customers would have saved nearly $8 million in excess natural gas expenses.
The Commission responds that its determination that TNC prudently operated the
Oklaunion power plant was supported by substantial evidence, including testimony that, during the
entire 18-month reconciliation period, Oklaunion had a capacity factor of 73.7 percent that exceeded
the national average for plants of the same size. The Commission found that, “[a]ccording to North
American Electric Reliability Council (NERC) Generation Adequacy Data Systems (GAD), coal
plants of similar size had an average three-year capacity factor of 73.3%, an average five-year capacity
factor of 72.1%, and an average six-year capacity factor of 71.7%.”17 If a power plant’s performance
over an entire reconciliation period is reasonable, argues the Commission, that its performance may
be below average during a portion of the reconciliation period does not justify a disallowance. The
Commission found that Oklaunion’s level of performance over the entire reconciliation period
was reasonable.
Cities presented no evidence to refute the Commission’s determinations that TNC
prudently operated the Oklaunion power plant during the entire reconciliation period and that the
17
Order on Rehearing at 18 (Oct. 18, 2004).
26
plant’s level of performance over the entire reconciliation period was reasonable. We conclude the
Commission’s findings are supported by substantial evidence. City of El Paso v. Public Util.
Comm’n, 883 S.W.2d at 185; Charter Med., 665 S.W.2d at 452. Cities’ third issue is overruled.
Maintenance Outage at the Oklaunion Plant
In 2001, TNC’s Oklaunion power plant experienced a major planned maintenance
outage. Cities assert that the Commission allowed ratepayers to subsidize TNC’s unregulated
generation company in violation of PURA. They allege the following: (1) TNC could have complied
with industry standards and performed the major inspection in 2002 following the onset of
deregulation; (2) had the maintenance been performed in 2002, Oklaunion would have operated at
an 80.7-percent capacity factor; and (3) by performing the overhaul in 2001 instead of 2002,
ratepayers paid millions more for gas generation and prepared Oklaunion for operation in the
deregulated market, greatly benefitting the unbundled generation company. PURA requires the
Commission to “adopt rules and enforcement procedures to govern transactions or activities between
a transmission and distribution utility and its competitive affiliates to avoid potential market power
abuses and cross-subsidizations between regulated and competitive activities both during the
transition to and after the introduction of competition.” PURA § 39.157(d) (West 2007). Cities argue
that the Commission, in violation of section 39.157(d) of PURA, subsidized TNC’s unregulated
generation company by allowing TNC to perform the major ten-week inspection and outage of the
Oklaunion plant in 2001 rather than in 2002.
Section 39.157 of PURA commands the Commission to monitor the market power
of those involved in the generation, transmission, distribution, and sale of electricity and to remedy
27
abusive behavior. Id. § 39.157(a); see TXU Generation Co. v. Public Util. Comm’n, 165 S.W.3d 821,
831 (Tex. App.—Austin 2005, pet. denied). “Market power abuses” include predatory pricing,
withholding of production, precluding energy, and collusion. Id.
Oklaunion’s last major outage took place in 1995. The record shows that a major
inspection outage occurs approximately every 52,000 to 60,000 hours, and the outage in this case
occurred within that hourly range. The record further indicates that a major inspection generally
requires eight weeks of unit down time, and the Commission found that Oklaunion’s planned outage
in 2001 fell within the unit’s maintenance guidelines. Cities having presented no evidence that the
timing of the Oklaunion’s outage was imprudent or unreasonable, we hold that the Commission did
not err in finding that TNC prudently managed Oklaunion during the reconciliation period. Cities’
fourth issue is overruled.
CONCLUSION
Having overruled all the issues raised on appeal by TNC and Cities, we affirm the
district court’s judgment upholding the Commission’s final order.
____________________________________
David Puryear, Justice
Before Chief Justice Jones, Justices Puryear and Waldrop
Affirmed
Filed: August 31, 2009
28